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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, 2000
OR

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

FOR THE TRANSITION PERIOD FROM ______________ TO ______________

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 Identification No.)
incorporation or organization)

TWO TOWER CENTER, 20TH FLOOR, EAST BRUNSWICK, NJ 08816
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (732) 247-4822
------------------------

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 26, 2000 was approximately $922,466,050.

Common Shares outstanding at September 26, 2000: 97,027,693

DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Proxy Statement with
respect to the Annual Meeting of Shareholders are incorporated by reference in
Part III of this report.

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KEY ENERGY SERVICES, INC.

INDEX

PART I.

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

Item 2. Properties.................................................. 9

Item 3. Legal Proceedings........................................... 11

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

PART II.

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

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 22
Risk......................................................

Item 8. Consolidated Financial Statements and Supplementary Data.... 23

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

PART III.

Item 10. Directors and Executive Officers of the Registrant.......... 59

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

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

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

PART IV.

Item 14. Exhibits, Financial Statements and Reports on Form 8-K...... 59

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 1,400 well
service rigs and 1,200 fluid hauling vehicles as of June 30, 2000. Key provides
a complete range of well services to major 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 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. Key is also a leading onshore
drilling contractor, with 73 land drilling rigs as of June 30, 2000. 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 offices are located at Two Tower Center, 20th
Floor, East Brunswick, New Jersey 08816. Key's phone number is (732) 247-4822
and website address is www.keyenergy.com.

BUSINESS STRATEGY

Key has built its leadership position through the consolidation of smaller,
less viable competitors. This consolidation, together with a continuing decline
in the number of available domestic well service rigs due to attrition,
cannibalization and transfers outside of the United States, has given Key the
opportunity to capitalize on improved market conditions which existed during
fiscal 2000. 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, 2000, Key's long-term
funded debt net of cash (net funded debt) was approximately $534,816,000 and its
net funded debt to capitalization was approximately 58% as compared to
approximately $656,194,000 and 69%, respectively, at June 30, 1999. 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 in conjunction
with highly trained and motivated employees. As a result, Key is able to offer
proactive solutions for most of the situations encountered at the wellsite. Key
ensures consistent high standards of quality and customer satisfaction by
continually evaluating its performance. Key maintains strong alliances with
several major oil and natural gas production companies as well as several
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 cash flow, both from operations and from anticipated
interest savings from reduced levels of debt, combined with the increased
revolver availability, 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 FISCAL 2000

INDUSTRY RECOVERY

During the fourth quarter of calendar year 1997, an imbalance began to
develop in the supply and the demand for crude oil. Reduced demand was fueled by
the Asian recession and two consecutive unusually warm winters in North America.
The supply of crude oil increased as a result of increased production quotas by
the Organization of Petroleum Exporting Countries ("OPEC") and renewed
production by Iraq. The resulting excess supply of crude oil caused significant
declines in crude oil prices during calendar year 1998 and the first quarter of
calendar year 1999. Crude oil prices averaged $14 to $15 per barrel during
calendar year 1998 compared to $20 to $21 per barrel during calendar year 1997
and reached a 12-year low of below $11.00 per barrel in December 1998. Natural
gas prices were also lower during the second half of calendar year 1998 as
unusually warm winters in North America during calendar years 1997 and 1998
resulted in weaker demand with prices reaching a low of approximately $1.60 per
Mcf in early calendar year 1999. Reduced prices for crude oil and natural gas
led to a sharp decline in the demand for oilfield services as oil and natural
gas companies significantly reduced capital spending for exploration,
development and production activities well into calendar year 1999. Key's
operations were significantly impacted by the downturn in the industry
throughout fiscal 1999, and, in response to this downturn, Key reduced operating
and administrative costs and delayed capital spending.

In March 1999, OPEC and other non-OPEC oil-producing countries,
substantially reduced production to a point which, together with improving
demand for oil, caused crude oil prices to recover

significantly through the spring and summer of 1999. In addition, these oil
producing countries agreed to production quotas to be adjusted based on demand
in order to keep crude oil prices in the range of $22 to $28 per barrel. The
successful implementation and subsequent adherence to these quotas, along with
improving demand, have led to increased crude oil prices during fiscal 2000 with
WTI Cushing prices averaging $25.97 per barrel during such period. In addition,
domestic natural gas prices increased significantly due to increased demand
during that period with Nymex Henry Hub prices averaging $3.04 per Mcf during
such period.

This increase in commodity prices led to a steady, sequential increase in
the demand for Key's services and equipment during fiscal 2000 as Key's
customers increased their exploration and development activity in Key's primary
market areas. This increase in demand resulted in sequential increases in
revenues, cash flow and net income in each quarter of fiscal 2000 over the same
quarter of fiscal 1999. Key expects demand for its services to remain at or
above current levels as long as commodity prices remain at or near their current
levels.

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 2000, Key significantly reduced its long-term debt and
strengthened its balance sheet. At June 30, 2000, Key's net funded debt was
approximately $534,816,000 and its net funded debt to capitalization was
approximately 59% as compared to approximately $656,194,000 and 69%,
respectively, at June 30, 1999. Proceeds from the Equity Offering (defined
below), the Production Payment (defined below) and exercises of options and
warrants, and 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 June 30, 2000, Key closed the public offering of 11,000,000 shares of
common stock at $9.625 per share, or approximately $106 million (the "Equity
Offering"). Net proceeds from the Equity Offering were approximately
$101 million, approximately $25.3 million of which was used to immediately repay
a portion of Key's senior credit facility term loans (approximately $23 million
for the Tranche A term loan and approximately $2.3 million for the Tranche B
term loan) and $65 million of which was subsequently used to repay a portion of
the senior credit facility revolver. After these repayments, the Tranche A term
loan had been paid in full, the Tranche B term loan had been reduced to
approximately $174 million, and the revolver had been reduced to approximately
$28 million. The remainder of the net proceeds were used to retire other
long-term debt. As a result of the Equity Offering, total shares outstanding as
of June 30, 2000 were approximately 96.8 million, an increase of approximately
12.8% over the amount outstanding immediately prior to the Equity Offering (see
Note 10 to Consolidated Financial Statements--Stockholders' Equity).

VOLUMETRIC PRODUCTION PAYMENT

In March 2000, Key sold a part of its future oil and natural gas production
from Odessa Exploration Incorporated ("Odessa Exploration"), 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 Mmbtu 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. The transaction is referred to elsewhere in this report
as the "Production Payment."

DESCRIPTION OF BUSINESS SEGMENTS

Key operates in three business segments which are well servicing, contract
drilling and oil and natural gas production. Our operations are conducted both
domestically and in Argentina and Canada. The following is a description of each
of these business segments (for financial information regarding these business
segments, see Note 15 to Consolidated Financial Statements--Business Segment
Information).

WELL SERVICING

Key provides a full range of well services, including rig-based services,
oilfield trucking services and 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's well service rig fleet performs four major rig services to oil and
natural gas operators.

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
natural gas and oil 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 a natural gas well, and removing debris such as
sand and paraffin from the well. Other services include pulling the rods,
tubing, pumps and other downhole equipment out of the wellbore to identify and
repair a production problem.

Maintenance services are often performed on a series of wells in proximity
to each other and typically require less than 48 hours per well to complete. The
general demand for maintenance services is closely related to the total number
of producing oil and natural gas wells in a geographic market, and maintenance
services are generally the most stable type of well service activity. The
average cost of a maintenance job typically ranges between $800 and $1,500,
excluding the costs of parts, services and other vendors at the wellsite.

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
average cost of a workover project typically ranges between $5,000 and $50,000,
excluding the costs of parts, services and other vendors at the wellsite, and is
usually less expensive than drilling a new well.

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
natural gas or oil 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. The average cost of a
completion typically ranges between $5,000 and $50,000, excluding the costs of
parts, services and other vendors at the wellsite.

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

Key provides 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. These trucks are also utilized in connection
with drilling and workover projects, which tend to produce and use large amounts
of various oilfield fluids. Key also owns a number of salt water disposal wells.
In addition, Key provides haul/ equipment trucks that are used to move large
pieces of equipment from one wellsite to the next.

ANCILLARY OILFIELD SERVICES

Key provides ancillary oilfield services, which include among others: hot
oiling; wireline; frac tank rentals; well site construction; roustabout
services; fishing and other tool rentals; supplying blowout preventers (BOPs);
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 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. Drilling services are
primarily provided under standard dayrate, footage or turnkey contracts.
Drilling rigs vary in size and capability and may include specialized equipment.
The majority of Key's drilling rigs are equipped with mechanical power systems
and have depth ratings ranging from 4,500 feet to 20,000 feet for an average of
approximately 8,700 feet.

OIL AND NATURAL GAS PRODUCTION

Key is engaged in the production of oil and natural gas in the Permian Basin
and Panhandle regions of West Texas through Odessa Exploration. Odessa
Exploration manages interests in oil and natural gas producing properties for
its own account and for drilling partnerships which it sponsors. Odessa
Exploration operates oil and natural gas wells on behalf of over 250 working
interest owners as well as for its own account.

FOREIGN OPERATIONS

Key also operates each of its business segments discussed above in Argentina
and Ontario, Canada. Key's foreign operations currently own 24 well servicing
rigs, 45 oilfield trucks and seven drilling rigs in Argentina and one well
servicing rig, two oilfield trucks and three drilling rigs in Ontario, Canada.

CUSTOMERS

Key's customers include major oil and natural gas production companies,
foreign national oil and natural gas production companies and independent oil
and gas production companies. No single customer in fiscal 2000 accounted for
10% or more of Key's consolidated revenues.

COMPETITION AND OTHER EXTERNAL FACTORS

Despite the significant consolidation in the domestic well servicing
industry, there are several smaller companies that compete in Key's well
servicing markets. Nonetheless, Key believes that its performance, equipment,
safety, pricing, 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. 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.

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 drilling industry is less consolidated
than the well servicing industry, resulting in a 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 oilfield services fluctuates, in part, in relation to the
demand for oil and natural gas. As demand for those commodities 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, 2000, Key employed approximately 7,436 persons (approximately
7,374 in oilfield and drilling services, nine in oil and natural gas production
and 53 in corporate). 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 consider its
relations with its employees to be satisfactory.

ENVIRONMENTAL REGULATIONS

Key's oilfield service operations, oil and natural gas production and
drilling activities are subject to various local, state and federal laws and
regulations intended to protect the environment. Key's operations routinely
involve the handling of waste materials, some of which are classified as
hazardous substances. Consequently, the regulations applicable to Key's
operations include those with respect to containment, disposal and controlling
the discharge of any hazardous oilfield waste and other non-hazardous waste
material into the environment, requiring removal and cleanup under certain
circumstances, or otherwise relating to the protection of the environment. Laws
and regulations protecting the environment have become more stringent in recent
years, and may in certain circumstances impose "strict liability," rendering a
party liable for environmental damage without regard to negligence or fault on
the part of such party. Such laws and regulations may expose us 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 offices are located in East Brunswick, New Jersey and
Midland, Texas. Key leases office space in both locations from independent third
parties.

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 oilfield service divisions as of June 30,
2000:

WELL SERVICE/ OILFIELD DRILLING
OPERATING DIVISION WORKOVER RIGS TRUCKS RIGS
- ------------------ ------------- -------- --------

DOMESTIC:
Permian Basin................................. 454 245 0
Gulf Coast.................................... 236 210 2
Mid-Continent................................. 294 262 0
Four Corners.................................. 70 76 19
Eastern....................................... 86 236 3
Rocky Mountain................................ 107 11 2
California.................................... 122 24 0
Key Energy Drilling (Permian Basin)........... 0 41 36

DOMESTIC SUBTOTAL............................... 1,369 1,105 62
INTERNATIONAL:
Argentina..................................... 28 64 7
Canada........................................ 2 2 4
TOTALS.......................................... 1,399 1,171 73

The Permian Basin Well Servicing division owns 33 and leases ten office and
yard locations. The Gulf Coast division owns 16 and leases 18 office and yard
locations. The Mid-Continent division owns 25 and leases 28 office and yard
locations. The Four Corners division owns seven and leases six office and yard
locations. The Eastern division owns four and leases 9 office and yard
locations. The Rocky Mountain division owns 17 and leases four office and yard
locations. The California division owns one and leases one office and yard
locations. The Permian Basin Drilling division owns one and leases two office
and yard locations. The Argentina division owns two and leases one office and
yard locations. The Canadian operation owns one yard location.

All operating facilities are metal one story office and/or shop buildings.
All buildings are occupied and considered to be in satisfactory condition.

OIL AND NATURAL GAS PRODUCTION

Odessa Exploration's major proved producing properties are located primarily
in the Permian Basin area of West Texas and in the Texas Panhandle. Odessa
Exploration leases office space in Odessa, Texas.

As of June 30, 2000, Odessa Exploration owned interests in 515 gross (348
proved developed) oil properties and 53 gross (45 proved developed) gas
properties. In March 2000, Odessa Exploration sold a part of its future oil and
natural gas production 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 gas properties in amounts ranging from 3,500 to
10,000 barrels of oil and 58,800 to 122,100 Mmbtu 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.
Including sales allocated to this forward sale, during the fiscal year ended
June 30, 2000, Odessa Exploration produced and sold 202,770 barrels of oil at an
average price of $20.00 per barrel and 1.883 MMcf of natural gas at an average
sales price of $2.67 per Mcf. Average production (lifting) costs were
approximately $6.60 per barrel of oil equivalent (one barrel of oil equals six
thousand cubic feet of natural gas). Excluding volumes allocated to

this forward sale, Odessa Exploration had total proved oil and natural gas
reserves (developed and undeveloped) as of June 30, 2000 valued at approximately
$71,394,308.(1)

ITEM 3. LEGAL PROCEEDINGS AND OTHER ACTIONS.

See Note 4 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, 2000, there were 678 registered holders of
97,209,504 issued and outstanding shares of common stock, including 416,666
shares of common stock held in treasury (96,792,838 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
2000 and fiscal 1999, as derived from published sources.

HIGH LOW
------------- ------------

Fiscal Year Ending 2000:
Fourth Quarter............................................ 11 7/8 8 1/16
Third Quarter............................................. 12 1/4 5
Second Quarter............................................ 5 7/8 3 7/8
First Quarter............................................. $ 5 13/16 $ 3 3/8
Fiscal Year Ending 1999:
Fourth Quarter............................................ 4 1/2 2 15/16
Third Quarter............................................. 5 5/8 3 1/16
Second Quarter............................................ 11 3/8 3 5/16
First Quarter............................................. $ 14 15/16 $ 6 1/8

There were no dividends paid on Key's common stock during the fiscal years
ended June 30, 2000, 1999 or 1998. 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.

- ------------------------

(1) Estimates of Odessa Exploration's proved oil and gas reserves as of
June 30, 2000 were prepared by the Company and reviewed by an independent
petroleum reservoir engineering firm. Estimates were made in accordance with
guidelines established by the Securities and Exchange Commission. Proved oil and
gas reserves are the estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic
conditions, i.e. prices and costs as of the date the estimate is made. Prices
utilized reflect consideration of changes in existing prices provided by
contractual arrangements, if any, but not of escalations based upon future
conditions. The reserve estimates are presented utilizing an average oil price
of $31.50 Bbl and an average natural gas price of $4.84 Mcf as of June 30, 2000.
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing equipment and operating methods. Proved undeveloped
oil and gas reserves are proved reserves that are expected to be recovered from
new wells or undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion or secondary or tertiary recovery.

RECENT SALES OF UNREGISTERED SECURITIES

Key did not make any unregistered sales of its securities during the twelve
months ended June 30, 2000 that were not previously included in its Quarterly
Reports filed for such period.

ITEM 6. SELECTED FINANCIAL DATA.

FISCAL YEAR ENDED JUNE 30,
---------------------------------------------------------
2000 1999(1) 1998 1997 1996(1)
---------- ---------- --------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

OPERATING DATA:
Revenues................................................ $ 637,732 $ 491,817 $ 424,543 $165,773 $ 66,007
Operating costs:
Direct costs.......................................... 462,386 371,428 293,448 114,598 47,112
Depreciation, depletion and amortization.............. 70,972 62,074 31,001 11,076 4,701
General and administrative............................ 58,772 53,108 38,987 17,447 6,011
Bad debt expense...................................... 1,648 5,928 826 98 131
Debt issuance costs................................... -- 6,307 -- -- --
Restructuring charge.................................. -- 4,504 -- -- --
Interest.............................................. 71,930 67,401 21,476 7,879 2,477
Income before income taxes and minority interest........ (27,976) (78,933) 38,805 14,675 5,575
Net income.............................................. (18,959) (53,258) 24,175 9,098 3,586
INCOME PER COMMON SHARE:
Basic................................................. $ (0.23) $ (1.94) $ 1.41 $ 0.81 $ 0.46
Diluted............................................... $ (0.23) $ (1.94) $ 1.23 $ 0.66 $ 0.45
Average common shares outstanding:
Basic................................................. 83,815 27,501 17,153 11,216 7,789
Assuming full dilution................................ 83,815 27,501 24,024 17,632 7,941
Common shares outstanding at period end................. 97,210 82,738 18,267 12,298 10,414
Market price per common share at period end............. $ 9.64 $ 3.56 13.12 17.81 8.19
Cash dividends paid on common shares.................... $ -- $ -- $ -- $ -- $ --
BALANCE SHEET DATA:
Cash.................................................. $ 109,873 $ 23,478 $ 25,265 $ 41,704 $ 4,211
Current assets........................................ 253,589 132,543 127,557 93,333 27,481
Property and equipment................................ 920,437 871,940 547,537 227,255 96,127
Property and equipment, net........................... 760,561 769,562 499,152 208,186 87,207
Total assets.......................................... 1,246,265 1,148,138 698,640 320,095 121,722
Current liabilities................................... 97,624 73,151 48,029 33,142 24,339
Long-term debt, including current portion............. 666,600 699,978 399,779 174,167 46,825
Stockholders' equity.................................. 382,887 288,094 154,928 73,179 41,624
OTHER DATA:
Adjusted EBITDA(2).................................... $ 116,574 $ 67,281 $ 92,108 $ 33,728 $ 12,884
Net cash (used in) provided by:
Operating activities................................ 37,051 (13,427) 40,925 843 7,121
Investing activities................................ (37,766) (294,654) (306,339) (80,749) (13,551)
Financing Activities................................ 87,110 306,294 248,975 117,399 9,366
Working capital..................................... 155,965 59,392 79,528 60,191 3,142
Book value per common share(3)...................... $ 3.94 $ 3.47 $ 8.48 $ 5.95 $ 4.00

- ------------------------------

(1) THE FINANCIAL DATA FOR THE YEAR ENDED JUNE 30, 1996 INCLUDES THE ALLOCATED
PURCHASE PRICE OF WELLTECH EASTERN AND THE RESULTS OF THEIR OPERATIONS,
BEGINNING MARCH 27, 1996. THE 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 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 INCOME TAXES, CASH FLOWS FROM OPERATING ACTIVITIES OR ANY
OTHER MEASURE OF FINANCIAL PERFORMANCE PRESENTED IN ACCORDANCE WITH
GENERALLY ACCEPTED ACCOUNTING PRINCIPLES. ADJUSTED EBITDA IS NOT A MEASURE
OF FINANCIAL PERFORMANCE UNDER 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 OUTSTANDING COMMON SHARES AT PERIOD END.

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 Reform Act.
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. Please note that certain reclassifications
have been made to the fiscal 1999 and 1998 financial data presented below to
conform to the fiscal 2000 presentation. The reclassifications consist primarily
of reclassifying as drilling revenues and expenses, revenues and expenses from
the limited drilling operations conducted by certain of the Company's well
servicing divisions that were previously included in well servicing revenues and
expenses in order to report the results of all drilling operations separately.

RESULTS OF OPERATIONS

FISCAL YEAR ENDED JUNE 30, 2000 VERSUS FISCAL YEAR ENDED JUNE 30, 1999

The Company's results of operations for the year ended June 30, 2000 reflect
the impact of the recent industry recovery resulting from increased commodity
prices which in turn caused increased demand for the Company's equipment and
services during fiscal 2000 (see Part I--Item 1--Major Developments During
Fiscal 2000--Industry Recovery). 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, 2000 increased $145,915,000, or 29.7%,
to $637,732,000 from $491,817,000 in fiscal 1999, while net income for fiscal
2000 increased $34,299,000 to a net loss of $18,959,000 from a net loss of
$53,258,000 in fiscal 1999. The increase in revenues is due to improved
operating conditions and higher rig hours, the full year effect of the
acquisitions completed during the early portion of fiscal 1999 and, to a lesser
extent, higher pricing. The decrease in net loss is the result of improved
operating conditions, higher pricing, and cost reduction initiatives. In
addition, fiscal 1999 included non-recurring charges for debt issuance costs and
restructuring initiatives as well as higher bad debt expense.

OPERATING REVENUES

WELL SERVICING. Well servicing revenues for the year ended June 30, 2000
increased $125,835,000 or 29%, to $559,492,000 from $433,657,000 in fiscal 1999.
The increase was due to increased demand for the Company's well servicing
equipment and services, the full year effect of the acquisitions completed
during the early portion of fiscal 1999 and, to a lesser extent, higher pricing.

CONTRACT DRILLING. Contract drilling revenues for the year ended June 30,
2000 increased $17,815,000, or 35.2%, to $68,428,000 from $50,613,000 in fiscal
1999. The increase was due to increased demand for the Company's contract
drilling equipment and services, the full year effect of the acquisition
completed during the early portion of fiscal 1999 and, to a lesser extent,
higher pricing.

OIL AND NATURAL GAS PRODUCTION. Oil and natural gas production revenues for
the year ended June 30, 2000 increased $2,930,000, or 45.3%, to $9,391,000 from
$6,461,000 in fiscal 1999. The increase was due to a 44% increase in the price
of oil and gas received on a barrel of oil equivalent (BOE) basis in fiscal 2000

compared to fiscal 1999, partially offset by a 2% decrease in the volume of oil
and gas produced on a BOE basis.

OPERATING EXPENSES

WELL SERVICING. Well servicing expenses for the year ended June 30, 2000
increased $74,975,000, or 23.1%, to $399,940,000 from $324,965,000 in fiscal
1999. 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 74.9% for fiscal
1999 to 71.5% for fiscal 2000. 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,
2000, increased $14,743,000, or 33.8%, to $58,299,000 from $43,556,000 in fiscal
1999. 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 86.1% in
fiscal 1999 to 85.2% in fiscal 2000. The margin improvement is due to improved
operating efficiencies and the effects of higher pricing.

OIL AND NATURAL GAS PRODUCTION. Oil and natural gas production expenses for
the year ended June 30, 2000, increased $1,240,000, or 42.7%, to $4,147,000 from
$2,907,000 in fiscal 1999. The increase is due to higher production costs
partially offset by lower production. Oil and natural gas production costs
increased from $5.50 per BOE in fiscal 1999 to $6.60 per BOE in fiscal 2000. The
increase in cost per BOE is primarily due to increased costs incurred in
bringing previously dormant wells back into production.

DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE

The Company's depreciation, depletion and amortization expense for the year
ended June 30, 2000 increased $8,898,000, or 14.3%, to $70,972,000 from
$62,074,000 in fiscal 1999. The increase is due to higher capital expenditures
incurred during fiscal 2000 as the Company refurbished equipment and increased
utilization of its contract drilling equipment (which it depreciates based on
utilization).

GENERAL AND ADMINISTRATIVE EXPENSES

The Company's general and administrative expenses for the year ended June
30, 2000 increased $5,664,000, or 10.7%, from $53,108,000 to $58,772,000 in
fiscal 2000. The increase was due to higher administrative costs necessitated by
the growth of the Company's operations as a result of the fiscal 1999
acquisitions and improved industry conditions. Despite the increased costs,
general and administrative expenses as a percentage of total revenues declined
from 10.8% in fiscal 1999 to 9.2% in fiscal 2000.

INTEREST EXPENSE

The Company's interest expense for the year ended June 30, 2000 increased
$4,529,000, or 6.7%, to $71,930,000 from $67,401,000 in fiscal 1999. The
increase was primarily due to the full year effect of the debt incurred in
connection with the acquisitions completed during the early portion of fiscal
1999, and, to a lesser extent, higher interest rates during fiscal 2000
partially offset by the impact of the long-term debt reduction during fiscal
2000.

BAD DEBT EXPENSE

The Company's bad debt expense for the year ended June 30, 2000 decreased
$4,280,000, or 72.2%, to $1,648,000 from $5,928,000 in fiscal 1999. The decrease
was primarily due to improved industry conditions for Key's customers and, to a
lesser extent, the centralization of the Company's internal credit approval
process.

EXTRAORDINARY GAIN

During the fourth quarter of fiscal 2000, the Company repurchased
$10,190,000 of its 5% Convertible Subordinated Notes which resulted in an
after-tax gain of $1,611,000.

INCOME TAXES

The Company's income tax benefit for the year ended June 30, 2000 decreased
$18,269,000 to $7,406,000 from $25,675,000 in fiscal 1999. The decrease in
income tax benefit is due to the decrease in pretax loss. The Company's
effective tax benefit rate for fiscal 2000 and 1999 was 26.5% and 32.5%,
respectively. The fiscal 2000 effective tax benefit rate is different from the
statutory rate of 35% because of the disallowance of certain goodwill
amortization and other non-deductible expenses. The decrease in the fiscal 2000
effective tax benefit rate was due to an increase in the amount of disallowed
items primarily as a result of the full year effect of the goodwill amortization
of the acquisitions completed during the early portion of fiscal 1999. The
Company does not expect to be required to remit significant federal income taxes
for the next few fiscal years because of the availability of net operating loss
carryforwards from fiscal 2000 and previous years.

CASH FLOW

The Company's net cash provided by operating activities for the year ended
June 30, 2000 increased $50,478,000 to a positive $37,051,000 from a negative
$13,427,000 in fiscal 1999. The increase is due to higher revenues resulting
from increased demand for the Company's equipment and services, the full year
effect of the acquisitions completed during the early portion of fiscal 1999
and, to a lesser extent, 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, 2000 decreased $256,888,000, or 87.2%, to $37,766,000 from $294,654,000 in
fiscal 1999. The decrease is due to no acquisitions having occurred during
fiscal 2000 partially offset by higher capital expenditures.

The Company's net cash provided by financing activities for the year ended
June 30, 2000 decreased $219,184,000, or 71.6%, to $87,110,000 from $306,929,000
in fiscal 1999. The decrease is primarily the result of significantly decreased
borrowings during fiscal 2000 and, to a lesser extent, the repayment of
long-term debt partially offset by proceeds from the Equity Offering and the
Production Payment.

FISCAL YEAR ENDED JUNE 30, 1999 VERSUS FISCAL YEAR ENDED JUNE 30, 1998

The Company's results of operations for the year ended June 30, 1999 reflect
the impact of a significant and unprecedented decline in demand for the
Company's equipment and services in all of the Company's lines of business
experienced from December 1998 to March 1999. The Company believes that the
decline in demand for its equipment and services during fiscal 1999 was due
solely to the adverse impact on its customers' capital spending caused by a
decline in oil prices to a twelve-year low of below $11.00 per barrel in
December 1998, and, to a lesser extent, a significant decline in natural gas
prices (see Part I--Item 1--Major Developments During Fiscal 2000--Industry
Recovery). Near the beginning of this decline, during the first four months of
fiscal 1999, the Company completed seven acquisitions. While the positive impact
of these fiscal 1999 acquisitions (as well as the impact of a full 12 months of
the prior fiscal year's acquisitions) on the Company's revenues compensated for
the negative revenue impact of the decline in business, the acquisitions could
not compensate for and could only partially offset the Company's decline in net
income (see Note 3 to Consolidated Financial Statements--Business and Property
Acquisitions).

THE COMPANY

Revenues for the year ended June 30, 1999 increased $67,274,000, or 15.8%,
to $491,817,000 in fiscal 1999 from $424,543,000 in fiscal 1998, while net
income for fiscal 1999 decreased $77,433,000 to a net loss of $53,258,000 in
fiscal 1999, from a positive $24,175,000 in fiscal 1998. The increase in
revenues was primarily due to well servicing and contract drilling acquisitions
completed during the latter portion of fiscal 1998 and the early portion of
fiscal 1999, partially offset by a significant decline in equipment utilization
and, to a lesser extent, pricing of oilfield services throughout fiscal 1999.
The decrease in net income is due to the decline in equipment utilization and,
to a lesser extent, pricing of oilfield services during most of fiscal 1999 and
the existence of a high level of fixed costs and expenses, including
depreciation, depletion and amortization, general and administrative, and
interest. In addition, fiscal 1999 included charges for bad debt expense, debt
issuance costs and restructuring that were far greater than such charges taken
during fiscal 1998.

OPERATING REVENUES

WELL SERVICING. Well servicing revenues for the year ended June 30, 1999
increased $77,419,000 or 21.7%, to $433,657,000 in fiscal 1999 from $356,238,000
in fiscal 1998. The increase in revenues was primarily due to acquisitions
completed during the latter portion of fiscal 1998 and the early portion of
fiscal 1999 partially offset by a significant decline in equipment utilization
and, to a lesser extent, pricing of oilfield services throughout fiscal 1999.

CONTRACT DRILLING. Revenues from contract drilling activities for the year
ended June 30, 1999 decreased $7,586,000, or 13%, to $50,613,000 in fiscal 1999
from $58,199,000 in fiscal 1998. The decrease in revenues was primarily due to a
significant decline in equipment utilization and, to a lesser extent, pricing of
oilfield services throughout fiscal 1999 partially offset by acquisitions
completed during the latter portion of fiscal 1998 and the early portion of
fiscal 1999.

OIL AND NATURAL GAS PRODUCTION. Revenues from oil and natural gas production
activities for the year ended June 30, 1999 decreased $569,000, or 8%, to
$6,461,000 in fiscal 1999 from $7,030,000 in fiscal 1998. The decrease in
revenues was primarily due to a 21% decrease in the price of oil and gas
received on a barrel of oil equivalent ("BOE") basis in fiscal 1999, compared to
fiscal 1998, partially offset by a 16% increase, from fiscal 1998 to fiscal
1999, in the volume of oil and gas produced on a BOE basis.

OPERATING EXPENSES

WELL SERVICING. Well servicing expenses for the year ended June 30, 1999
increased $77,360,000, or 31.2%, to $324,965,000 in fiscal 1999 from
$247,605,000 in fiscal 1998. The increase was primarily due to acquisitions
completed during the latter portion of fiscal 1998 and the early portion of
fiscal 1999 partially offset by a significant decline in equipment utilization
and, to a lesser extent, pricing of oilfield services throughout fiscal 1999.
Well servicing expenses, as a percentage of well servicing revenue, increased to
75% for fiscal 1999 from 69.5% for fiscal 1998. The increase was due to a shift
in revenue mix from higher margin, higher priced well services to lower margin,
lower priced well services, reduced pricing for well services, and a lag in
reducing costs in response to declines in utilization and revenues.

CONTRACT DRILLING. Expenses related to contract drilling activities for the
year ended June 30, 1999 increased $696,000, or 1.6%, from $42,860,000 in fiscal
1998 to $43,556,000 in fiscal 1999. The increase was primarily due to
acquisitions completed during the latter portion of fiscal 1998 and the early
portion of fiscal 1999 offset by a decline in equipment utilization and, to a
lesser extent, pricing of oilfield services throughout fiscal 1999. Contract
drilling expenses, as a percentage of contract drilling revenues, increased to
86.1% in fiscal 1999 from 73.6% in fiscal 1998. The increase was due to reduced
pricing for contract drilling and a lag in reducing costs in response to
declines in utilization and revenues.

OIL AND NATURAL GAS PRODUCTION. Expenses related to oil and natural gas
production activities for the year ended June 30, 1999 decreased $76,000, or 3%,
to $2,907,000 in fiscal 1999 from $2,983,000 in fiscal 1998. Oil and natural gas
production costs decreased to $5.50 per BOE in fiscal 1999 from $6.55 per BOE in
fiscal 1998. The decrease per BOE is primarily due to an increase in gas
production as compared to oil production, from the prior year, resulting from to
an acquisition of natural gas properties during the latter portion of fiscal
1998 and development drilling of natural gas wells during fiscal 1998 and the
early portion of fiscal 1999.

DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE

The Company's depreciation, depletion and amortization expense for the year
ended June 30, 1999 increased $31,073,000, or 100%, to $62,074,000 in fiscal
1999 from $31,001,000 in fiscal 1998. The increase is primarily due to an
increase in oilfield service depreciation resulting from the well servicing and
contract drilling acquisitions completed during the latter portion of fiscal
1998 and the early portion of fiscal 1999.

GENERAL AND ADMINISTRATIVE EXPENSES

The Company's general and administrative expenses for the year ended June
30, 1999 increased $14,121,000, or 36%, to $53,108,000 in fiscal 1999 from
$38,987,000 in fiscal 1998. The increase was primarily due to well servicing and
contract drilling acquisitions completed during the latter portion of fiscal
1998 and the early portion of fiscal 1999.

INTEREST EXPENSE

The Company's interest expense for the year ended June 30, 1999 increased
$45,925,000, or 214%, to $67,401,000 in fiscal 1999 from $21,476,000 in fiscal
1998. The increase was primarily due to additional debt incurred in connection
with the well servicing and contract drilling acquisitions completed during the
latter portion of fiscal 1998 and the early portion of fiscal 1999 and, to a
lesser extent, higher interest rates and amortization of additional debt
issuance costs (see Note 5 to Consolidated Financial Statements--Long Term
Debt).

BAD DEBT EXPENSE

The Company's bad debt expense for the year ended June 30, 1999 increased
$5,102,000, or 618%, to $5,928,000 in fiscal 1999 from $826,000 in fiscal 1998.
The increase was primarily due to the significant decline in commodity prices
and a corresponding deterioration in market conditions in fiscal 1999 causing a
small number of the Company's customers to become insolvent.

DEBT ISSUANCE COSTS

During fiscal 1999, the Company recorded an expense of $6,307,000, which
represented the write-off of debt issuance costs. The debt issuance costs were
associated with the Company's bridge loan which was subsequently repaid using
the proceeds from the Company's private offering of 14% Senior Subordinated
Notes.

RESTRUCTURING CHARGE

quarter ending March 31, 1999. However, due to an increase in oil and gas prices
beginning during the Company's fourth fiscal quarter, the Company amended its
restructuring plan to decrease the number of planned employee terminations.
Increased demand for the Company's services made such terminations unnecessary
and would have, in management's opinion, restricted the Company's ability to
provide services to its customers. Consequently, the Company did not utilize
approximately $3.7 million of the pretax charges. Essentially all of the
unutilized portion of the restructuring charge was reversed in the fourth
quarter ending June 30, 1999 resulting in a total pretax charge for the fiscal
year ended June 30, 1999 of approximately $4.5 million. The charges include
severance payments and other termination benefits for 97 employees, lease
commitments related to closed facilities and environmental studies performed on
closed leased yard locations.

INCOME TAXES

The Company's income tax expense for the year ended June 30, 1999 decreased
$40,305,000 to a benefit of $25,675,000 in fiscal 1999 from an expense of
$14,630,000 in fiscal 1998. The decrease in income taxes is due to the decrease
in pretax income. The Company's effective tax benefit rate for fiscal 1999 and
the Company's effective tax rate for fiscal 1998 was 32.5% and 37.7%,
respectively. The fiscal 1999 effective tax benefit rate is different from the
statutory rate of 35% because of the disallowance of certain goodwill
amortization, other non-deductible expenses and state and local taxes. The
Company does not expect to be required to remit federal income taxes for the
next few fiscal years because of the availability of net operating loss carry
forwards from fiscal 1999 and previous years.

CASH FLOW

The Company's net cash provided by operating activities for the year ended
June 30, 1999 decreased $54,352,000 to a negative $13,427,000 in fiscal 1999
from a positive $40,925,000 in fiscal 1998. The decrease is primarily due to the
decline in equipment utilization and, to a lesser extent, pricing of oilfield
services during throughout fiscal 1999 and the existence of a high level of
fixed costs, including general and administrative expenses and interest.

The Company's net cash used in investing activities for the year ended June
30, 1999 decreased $11,685,000, or 4%, to $294,654,000 in fiscal 1999 from
$306,339,000 in fiscal 1998. The decrease is primarily due to decreased capital
expenditures resulting from reduced equipment utilization.

The Company's net cash provided by financing activities for the year ended
June 30, 1999 increased $57,319,000 or 23%, to $306,294,000 in fiscal 1999 from
$248,975,000 in fiscal 1998. The increase is primarily the result of proceeds
from borrowings and the Equity Offering.

LIQUIDITY AND CAPITAL RESOURCES

The Company's cash and cash equivalents increased $86.4 million, or 368%, to
$109.9 million as of June 30, 2000, from $23.5 million as of June 30, 1999.

The Company projects approximately $45 million for capital expenditures for
fiscal 2001 as compared to $38 million and $31.3 million in fiscal 2000 and
1999, respectively. 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 the Credit Agreement, will be sufficient to fund such expenditures.

LONG-TERM DEBT

Other than capital lease obligations and miscellaneous notes payable, as of
June 30, 2000, the Company's long-term debt was comprised of (i) a senior credit
facility, (ii) a series of 14% Senior

Subordinated Notes Due 2009, (iii) a series of 5% Convertible Subordinated Notes
Due 2004, (iv) a series of 7% Convertible Subordinated Debentures Due 2003, and
(v) a series of 9 3/8% Senior Notes Due 2007.

SENIOR CREDIT FACILITY

In connection with the acquisition of Dawson Production Services, Inc.
("Dawson") the Company entered into a $550,000,000 Second Amended and Restated
Credit Agreement, dated as of June 6, 1997, as amended and restated through
September 14, 1998, among the Company, PNC Bank, National Association, as
Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent,
PNC Capital Markets, Inc., as Arranger, and the other lenders named from time to
time parties thereto (as subsequently amended, the "Credit Agreement").

The Credit Agreement provides for a senior credit facility consisting of
$150 million in revolving loans, $150 million in Tranche A term loan and
$200 million in Tranche B term loan. In addition, up to $20 million of letters
of credit can be issued under the Credit Agreement, but any outstanding letters
of credit reduces borrowing availability under the revolving loans. The Tranche
A term loan matures in sixteen consecutive quarterly installments commencing
December 14, 1999 with quarterly installment amounts equal to the applicable
percentage for a particular quarter multiplied by the unamortized principal
amount: 4% for installments 1-4, 6% for installments 5-8, 7% for installments
9-12 and 8% for installments 13-16. The Tranche B term loan matures in nineteen
consecutive quarterly installments commencing December 14, 1999 with quarterly
installment amounts equal to the applicable percentage for a particular quarter
multiplied by the unamortized principal amount: 0.25% for installments 1-16, 24%
for installments 17-18 and 48% for the final installment. The commitment to make
revolving loans will be reduced to $125 million and $100 million on
September 14, 2001 and September 14, 2002 respectively. The revolving commitment
will terminate on September 14, 2003, and all the revolving loans must be paid
on or before that date.

The revolving loans and the Tranche A term loan bear interest at rates based
upon, at the Company's option, either the prime rate plus a margin ranging from
0.75% to 2.00% or a Eurodollar rate plus a margin ranging from 2.25% to 3.50%,
in each case depending upon the ratio of the Company's total debt (less cash on
hand over $5 million) to the Company's trailing 12-month EBITDA, as adjusted.
The Tranche B term loan bears interest at rates based upon, at the Company's
option, either the prime rate plus 2.50% or a Eurodollar rate plus 4.00%. The
Company pays commitment fees on the unused portion of the revolving loan at a
varying rate (depending upon the pricing ratio) of between 0.25% and 0.50%.

During fiscal 2000, the Company repaid approximately $22.2 million under the
term loans while increasing net borrowings under the revolver by $3 million. As
a result, at June 30, 2000, the principal amount outstanding under (i) the
Tranche A term loan was approximately $23 million, (ii) the Tranche B term loan
was approximately $176 million and (iii) the revolver was approximately
$93 million. Additionally, at June 30, 2000, the Company had outstanding letters
of credit totaling approximately $15 million related to its workman's
compensation insurance.

Since June 30, 2000, a portion of the net proceeds from the Equity Offering
(see Note 10 to the Consolidated Financial Statements--Stockholders' Equity) was
used to repay the entire outstanding balance of the Tranche A term loan, and
$2.3 million of the Tranche B term loan, reducing the principal amount
outstanding under the Tranche B term loan to approximately $174 million. The
Tranche B term loan prepayments were applied to reduce mandatory repayment
installments of the Tranche B term loan pro rata, thereby equally reducing all
amortization payments without altering the amortization schedule. In addition
$65 million of the net proceeds from the Equity Offering was used to repay a
portion of the senior credit facility revolver reducing the amount outstanding
under the revolver immediately thereafter to approximately $28 million. The
remainder of the net proceeds of the Equity Offering was used to retire other
long term debt. The principal amount outstanding under the revolver has since
been further reduced to $23 million as of September 28, 2000.

See Note 5 to Consolidated Financial Statements--Long Term Debt for further
discussion of the Senior Credit Facility.

14% SENIOR SUBORDINATED NOTES

On January 22, 1999 pursuant to Rule 144A and Regulation S under the
Securities Act of 1933, as amended (the "Securities Act"), 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 2,032,565 shares of common stock at an exercise
price of $4.88125 per share (the "Unit Warrants"). The cash proceeds from the
private placement, net of fees and expenses, were used to repay substantially
all of the remaining $148.6 million principal amount (plus accrued interest)
owed under the Company's bridge loan facility arranged in connection with the
acquisition of 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
may redeem up to 35% of the aggregate principal amount of the Senior
Subordinated Notes with the proceeds of certain offerings of equity at 114% of
par, plus accrued interest.

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, as defined in the
indenture under which the 14% Senior Subordinated Notes were issued, includes
borrowings under the Credit Agreement and the Dawson 9 3/8% Senior Notes.

At June 30, 2000, $150,000,000 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 of
approximately $10,092,000 and $10,500,000 was paid on July 15, 1999 and
January 15, 2000, respectively. As of June 30, 2000, 52,000 Unit Warrants had
been exercised, producing approximately $3.7 million of proceeds to the Company
and leaving 98,000 Unit Warrants outstanding.

5% CONVERTIBLE SUBORDINATED NOTES

On September 25, 1997, the Company completed an initial closing of its
private placement of $200 million of 5% Convertible Subordinated Notes due 2004
(the "5% Convertible Subordinated Notes"). On October 7, 1997, the Company
completed a second closing of its private placement of an additional
$16 million of the 5% Convertible Subordinated Notes pursuant to the exercise of
the remaining portion of the over-allotment option granted to the initial
purchasers of the 5% Convertible Subordinated Notes. The placements were made as
private offerings pursuant to Rule 144A and Regulation S under the Securities
Act. The 5% Convertible Subordinated Notes are subordinate to the Company's
senior indebtedness, which, as defined in the indenture under which the 5%
Convertible Subordinated Notes were issued, includes borrowings under the Credit
Agreement, the 14% Senior Subordinated Notes and the Dawson 9 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 or after September 15, 2000, in whole or part, together with accrued
and unpaid interest. The initial redemption price is 102.86% for the year
beginning September 15, 2000 and declines ratably thereafter on an annual basis.

During the quarter ended June 30, 2000, the Company repurchased (and
canceled) $10,190,000 principal amount of the 5% Convertible Subordinated Notes,
leaving $205,810,000 principal amount of the 5% Convertible Subordinated Notes
outstanding at June 30, 2000. Since June 30, 2000, the Company repurchased (and
canceled) an additional $10,196,000 principal amount of the 5% Convertible
Subordinated Notes, leaving $195,614,000 outstanding as of September 28, 2000.
Interest on the 5% Convertible Subordinated Notes is payable on March 15 and
September 15. Interest of approximately $5.4 million was paid on September 15,
1999 and March 15, 2000.

7% CONVERTIBLE SUBORDINATED DEBENTURES

In July 1996, the Company completed a $52,000,000 private placement of 7%
Convertible Subordinated Debentures due 2003 (the "7% Convertible Subordinated
Debentures") pursuant to Rule 144A under the Securities Act. The 7% Convertible
Subordinated Debentures are subordinate to the Company's senior indebtedness,
which, as defined in the indenture under which the 7% Convertible Subordinated
Debentures were issued, includes borrowings under the Credit Agreement, the 14%
Senior Subordinated Notes and the Dawson 9 3/8% Senior Notes.

The Debentures are convertible, at any time prior to maturity, at the
holders' option, into shares of the Company's common stock at a conversion price
of $9.75 per share, subject to certain adjustments. In addition, holders who
converted prior to July 1, 1999 were entitled to receive a payment, in cash or
the Company's common stock (at the Company's option) generally equal to 50% of
the interest otherwise payable from the date of conversion through July 1, 1999.

During fiscal 2000, $3,600,000 in principal amount of the 7% Convertible
Subordinated Debentures was converted into 369,229 shares of the Company's
common stock. An additional 11,261 shares of common stock were issued
representing 100% of the interest otherwise payable from January 1, 2000 through
July 1, 2000. The additional 11,261 shares of common stock, representing 100% of
the interest otherwise payable from January 1, 2000 through July 1, 2000, are
included in equity. In addition, the proportional amount of unamortized debt
issuance costs associated with the converted 7% Convertible Subordinated
Debentures was charged to additional paid-in capital at the time of conversion.

At June 30, 2000, $1,000,000 principal amount of the 7% Convertible
Subordinated Debentures remained outstanding. On August 31, 2000, $985,000
principal amount of the 7% Convertible Subordinated Debentures were surrendered
for conversion by the holders thereof and 101,025 shares of common stock were
issued on September 1, 2000. On September 1, 2000, the remaining $15,000
principal amount of the outstanding 7% Convertible Subordinated Debentures was
redeemed at 103% of the principal amount plus accrued interest, leaving none
outstanding as of September 28, 2000. Interest on the 7% Convertible
Subordinated Debentures was payable on January 1 and July 1 of each year.
Interest of approximately $161,000 was paid on July 1, 1999 and January 1, 2000.

DAWSON 9 3/8% SENIOR NOTES

As the result of the Dawson acquisition, the Company, its subsidiaries and
U.S. Trust Company of Texas, N.A., as trustee ("U.S. Trust"), entered into a
Supplemental Indenture dated September 21, 1998 (the "Supplemental Indenture"),
pursuant to which the Company assumed the obligations of Dawson under the
Indenture dated February 20, 1997 (the "Dawson Indenture") between Dawson and
U.S. Trust. Most of the Company's subsidiaries guaranteed those obligations and
the senior notes due 2007 (the "Dawson 9 3/8% Senior Notes") issued pursuant to
the Dawson Indenture were equally and ratably secured with the obligations under
the Credit Agreement. On November 17, 1998 the Company completed a cash tender
offer to purchase the full $140,000,000 outstanding principal amount of Dawson
9 3/8% Senior Notes

at 101% of the aggregate principal amount of the notes, using borrowings under
the Credit Agreement. Under the tender offer, $138,594,000 in principal amount
of the Dawson 9 3/8% Senior Notes was redeemed and a premium of $1,386,000 was
paid. In addition, accrued interest of $4,078,000 was paid at redemption.

At June 30, 1999, $1,406,000 principal amount of the Dawson 9 3/8% Notes
remained outstanding. During the quarter ended June 30, 2000, the Company
repurchased $300,000 principal amount of the Dawson 9 3/8% Senior Notes, leaving
$1,106,000 principal amount of the Dawson 9 3/8% Senior Notes outstanding at
June 30, 2000. Since June 30, 2000, the Company repurchased an additional
$800,000 principal amount of the Dawson 9 3/8% Senior Notes, leaving $306,000
principal amount outstanding as of September 28, 2000. Interest on the Dawson
9 3/8% Senior Notes is payable on February 1 and August 1 of each year. Interest
of approximately $65,906 was paid on August 1, 1999 and February 1, 2000.

IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS

The Financial Accounting Standards Board has recently issued the following
accounting standard which will be adopted by Key in the future.

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" which, as amended, is effective for fiscal
years beginning after June 15, 2000. This statement establishes accounting and
reporting standards for derivative instruments and for hedging activities. Key
will adopt this statement effective July 1, 2000. The oil and gas collars
currently in place will be marked to market through the income statement until
such time as they are documented as hedges.

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, 2000, Key had long-term debt outstanding of $666,600,000. Of
this amount, $352,741,000 or 53%, bears interest at fixed rates as follows:

(000'S)
BALANCE AT
6/30/00
----------

5% Convertible Subordinated Notes Due 2004.................. $205,810
14% Senior Subordinated Notes Due 2009...................... 143,650
7% Convertible Subordinated Debentures Due 2003............. 1,000
Dawson 9 3/8% Senior Notes Due 2007......................... 1,106
Other (rates generally ranging from 8.0% to 8.5%)........... 1,175
--------
$352,741
========

The remaining $313,859,000 of debt outstanding as of June 30, 2000 bears
interest at floating rates which averaged approximately 10.01% at June 30, 2000.
A 10% increase in short-term interest rates on the floating-rate debt
outstanding at June 30, 2000 would equal approximately 100 basis points. Such an
increase in interest rates would increase Key's fiscal 2001 interest expense by
approximately $3.1 million 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

Key's net assets, net earnings and cash flows from its Argentina
subsidiaries are currently not exposed to foreign currency risk, as Argentina's
currency is tied to the U.S. dollar. Key's net assets, net earnings and cash
flows from its Canadian subsidiary is 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, expenses and cash flow 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 Key.

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.

Key periodically enters into financial hedging activities with respect to a
portion of its projected oil and natural gas production through commodity option
or collar contracts. Key pays a premium for its option contracts. Such premiums
are amortized to oil and natural gas revenues over the life of the related
option contracts. These financial hedging activities are intended to support oil
and natural gas prices at targeted levels and to manage Key's exposure to oil
and natural gas price fluctuations. Realized gains from the settlement of these
financial hedging instruments are recognized in oil and natural gas sales when
the associated production occurs. The gains and losses realized as a result of
these hedging activities are substantially offset in the cash market when the
hedged commodity is delivered.

As of June 30, 2000, Key had oil and gas price collars in place, which
represented 9,000 barrels of oil production per month and approximately 70,000
Mmbtu of gas production per month. The total fiscal 2000 hedged oil and natural
gas volumes represent approximately 46% and 40%, respectively, of expected
calendar year total production. A 10% increase in the index price of oil or gas
from their levels at June 30, 2000 would have no impact on the Company's net
assets, net earnings or cash flows (as derived from commodity option contracts).

ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Presented herein are the consolidated financial statements of Key Energy
Services, Inc. as of June 30, 2000 and 1999 and the years ended June 30, 2000,
1999 and 1998.

Also included is the report of KPMG LLP, independent certified public
accountants, on such consolidated financial statements as of June 30, 2000 and
1999 and for the years ended June 30, 2000, 1999 and 1998.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PAGE
--------

Consolidated Balance Sheets................................. 25

Consolidated Statements of Operations....................... 26

Consolidated Statements of Comprehensive Income............. 27

Consolidated Statements of Cash Flows....................... 28

Consolidated Statements of Stockholders' Equity............. 29

Notes to Consolidated Financial Statements.................. 30

Independent Auditors' Report................................ 58

KEY ENERGY SERVICES, INC.
CONSOLIDATED BALANCE SHEETS

JUNE 30, 2000 JUNE 30, 1999
-------------- --------------
(THOUSANDS, EXCEPT SHARE DATA)

ASSETS
Current assets:
Cash...................................................... $ 109,873 $ 23,478
Accounts receivable, net of allowance for doubtful
accounts ($3,189--2000, $6,790--1999)................... 123,203 91,998
Inventories............................................... 10,028 12,742
Income taxes receivable................................... 5,588 916
Prepaid expenses and other current assets................. 4,897 3,409
---------- ----------
Total current assets........................................ 253,589 132,543
---------- ----------
Property and equipment:
Well servicing equipment.................................. 670,392 655,578
Contract drilling equipment............................... 105,454 88,766
Motor vehicles............................................ 55,011 45,133
Oil and gas properties and other related equipment,
successful efforts method............................... 43,855 42,925
Furniture and equipment................................... 11,013 8,452
Buildings and land........................................ 34,712 31,086
---------- ----------
Total property and equipment................................ 920,437 871,940

Accumulated depreciation & depletion........................ (159,876) (102,378)
---------- ----------
Net property and equipment.................................. 760,561 769,562
---------- ----------
Goodwill, net............................................. 198,633 205,423
Deferred costs, net....................................... 18,855 23,779
Notes receivable--related parties......................... 5,150 2,835
Other assets.............................................. 9,477 13,996
---------- ----------
Total assets................................................ $1,246,265 $1,148,138
========== ==========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 35,801 $ 18,527
Other accrued liabilities................................. 26,398 25,291
Accrued interest.......................................... 15,994 13,079
Current portion of long-term debt......................... 14,655 16,254
Current portion of deferred revenue....................... 4,776 --
---------- ----------
Total current liabilities................................... 97,624 73,151
---------- ----------
Long-term debt, less current portion........................ 651,945 683,724
Deferred revenue, less current portion...................... 12,255 --
Non-current accrued expenses................................ 1,847 1,739
Deferred tax liability...................................... 99,707 101,430
Commitments and contingencies...............................
Stockholders' equity:
Common stock, $.10 par value; 100,000,000 shares
authorized, 97,209,504 and 83,155,072 shares issued, at
June 30, 2000 and June 30, 1999, respectively........... 9,723 8,317
Additional paid-in capital................................ 413,962 301,615
Treasury stock, at cost; 416,666 shares at June 30, 2000
and June 30, 1999....................................... (9,682) (9,682)
Accumulated other comprehensive income.................... 8 9
Retained earnings (deficit)............................... (31,124) (12,165)
---------- ----------
Total stockholders' equity.................................. 382,887 288,094
---------- ----------
Total liabilities and stockholders' equity.................. $1,246,265 $1,148,138
========== ==========

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

KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

YEAR ENDED JUNE 30,
------------------------------------
2000 1999 1998
---------- ---------- ----------
(THOUSANDS, EXCEPT PER SHARE DATA)

REVENUES:
Well servicing............................................ $559,492 $433,657 $356,238
Contract drilling......................................... 68,428 50,613 58,199
Oil and gas production.................................... 9,391 6,461 7,030
Other, net................................................ 421 1,086 3,076
-------- -------- --------
637,732 491,817 424,543
-------- -------- --------

COSTS AND EXPENSES:
Well servicing............................................ 399,940 324,965 247,605
Contract drilling......................................... 58,299 43,556 42,860
Oil and gas production.................................... 4,147 2,907 2,983
Depreciation, depletion and amortization.................. 70,972 62,074 31,001
General and administrative................................ 58,772 53,108 38,987
Bad debt expense.......................................... 1,648 5,928 826
Debt issuance costs....................................... -- 6,307 --
Interest.................................................. 71,930 67,401 21,476
Corporate restructuring................................... -- 4,504 --
-------- -------- --------
665,708 570,750 385,738

Income (loss) before income taxes........................... (27,976) (78,933) 38,805
-------- -------- --------
Income tax benefit (expense)................................ 7,406 25,675 (14,630)
-------- -------- --------

INCOME (LOSS) BEFORE EXTRAORDINARY GAIN..................... $(20,570) $(53,258) $ 24,175
Extraordinary gain on extinguishment of debt, less
applicable income taxes of $580 (See Note 5).............. 1,611 -- --
-------- -------- --------

NET INCOME (LOSS)........................................... $(18,959) $(53,258) $ 24,175
======== ======== ========

EARNINGS (LOSS) PER SHARE:

Basic--before extraordinary gain.......................... $ (0.25) $ (1.94) $ 1.41
Extraordinary gain, net of tax............................ 0.02 -- --
-------- -------- --------
Basic--after extraordinary gain........................... $ (0.23) $ (1.94) $ 1.41
======== ======== ========

Diluted--before extraordinary gain........................ $ (0.25) $ (1.94) $ 1.23
Extraordinary gain, net of tax............................ 0.02 -- --
-------- -------- --------
Diluted--after extraordinary gain......................... $ (0.23) $ (1.94) $ 1.23
======== ======== ========

WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic..................................................... 83,815 27,501 17,153
Diluted................................................... 83,815 27,501 24,024

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

KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

YEAR ENDED JUNE 30,
------------------------------
2000 1999 1998
-------- -------- --------
(THOUSANDS)

NET INCOME (LOSS)........................................... $(18,959) $(53,258) $24,175

OTHER COMPREHENSIVE INCOME, NET OF TAX:
Unrealized gains on available-for-sale securities, net of
tax..................................................... -- -- 1,525
Reversal of unrealized gains on available-for-sale
securities, net of tax.................................. -- (1,525) --
Foreign currency translation gain (loss), net of tax...... (1) 9 --
-------- -------- -------

COMPREHENSIVE INCOME (LOSS), NET OF TAX..................... $(18,960) $(54,774) $25,700
======== ======== =======

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

KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

YEAR ENDED JUNE 30,
--------------------------------
2000 1999 1998
-------- --------- ---------
(THOUSANDS)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income/(loss)......................................... $(18,959) $ (53,258) $ 24,175
ADJUSTMENTS TO RECONCILE INCOME FROM OPERATIONS TO NET
CASH PROVIDED BY (USED IN) OPERATIONS:
Depreciation, depletion and amortization.................. 70,972 62,074 31,001
Bad debt expense.......................................... 1,648 5,928 826
Amortization of deferred debt costs....................... 5,919 5,216 2,459
Restructuring charge...................................... -- 233 --
Deferred income taxes..................................... (1,818) (25,675) 7,287
(Gain) loss on sale of assets............................. 25 111 (189)
Other non-cash items...................................... -- 13 1,313
CHANGE IN ASSETS AND LIABILITIES NET OF EFFECTS FROM THE
ACQUISITIONS:
(Increase) decrease in accounts receivable.............. (32,853) 9,741 (3,999)
(Increase) decrease in other current assets............. (5,483) (432) (4,051)
Increase (decrease) in accounts payable, accrued
interest and accrued expenses......................... 18,875 (17,378) (17,897)
Other assets and liabilities............................ (1,275) -- --
-------- --------- ---------
Net cash provided (used) by operating activities.......... 37,051 (13,427) 40,925
-------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures--well servicing...................... (26,469) (26,776) (44,284)
Capital expenditures--contract drilling................... (8,282) (1,063) (5,385)
Capital expenditures--oil and gas......................... (917) (287) (7,849)
Capital expenditures--other............................... (2,505) (3,181) (1,748)
Proceeds from sale of fixed assets........................ 2,722 7,110 1,279
Notes receivable from related parties..................... (2,315) (2,835) --
Cash received in acquisitions............................. -- 27,008 2,903
Acquisitions--well servicing.............................. -- (292,638) (172,536)
Acquisitions--contract drilling........................... -- -- (49,440)
Acquisitions--oil and gas................................. -- -- (9,298)
Acquisitions--minority interest........................... -- -- (3,426)
Purchase of marketable equity securities.................. -- -- (9,979)
Other assets and liabilities.............................. -- (1,992) (6,576)
-------- --------- ---------
Net cash from (used) in investing activities.............. (37,766) (294,654) (306,339)
-------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of long-term debt and capital lease
obligations............................................. (53,268) (487,376) (237,424)
Borrowings under line-of-credit........................... 12,000 328,411 280,770
Proceeds from equity offering, net of expenses............ 100,571 180,441 --
Purchase of treasury stock................................ -- -- (9,682)
Proceeds from long-term debt.............................. -- 142,566 216,000
Proceeds paid for debt issuance costs..................... -- (15,274) (9,270)
Proceeds from other long-term debt........................ -- 150,000 3,316
Proceeds from forward sale, net of expenses............... 18,236 -- --
Proceeds from stock option warrants....................... -- 7,434 --
Proceeds from warrants exercised.......................... 8,473 -- 4,223
Proceeds from stock options exercised..................... 1,098 92 1,042
-------- --------- ---------
Net cash provided by (used in) financing activities....... 87,110 306,294 248,975
-------- --------- ---------
Net increase (decrease) in cash........................... 86,395 (1,787) (16,439)
Cash at beginning of period............................... 23,478 25,265 41,704
-------- --------- ---------
Cash at end of period..................................... $109,873 $ 23,478 $ 25,265
======== ========= =========

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

KEY ENERGY SERVICES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(THOUSANDS)

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

BALANCE AT JUNE 30, 1997........ 12,298 $1,230 $ 55,031 -- $ 16,918 -- $ 73,179
------ ------ -------- ------- -------- ------- --------

Issuance of common stock for
acquisition of assets......... 225 22 5,912 -- -- -- 5,934
Issuance of common stock for
acquisition of companies...... 340 34 7,895 -- -- -- 7,929
Exercise of warrants............ 609 61 4,162 -- -- -- 4,223
Exercise of options............. 209 21 1,021 -- -- -- 1,042
Conversion of 7% Debentures..... 5,062 506 45,282 -- -- -- 45,788
Purchase of treasury stock...... -- -- -- (9,682) -- -- (9,682)
Mark-to-market of available for
sale securities, net of tax... -- -- -- -- -- 1,525 1,525
Other........................... (58) (6) -- -- -- -- (6)
Net income (loss)............... -- -- -- -- 24,175 -- 24,175
------ ------ -------- ------- -------- ------- --------
BALANCE AT JUNE 30, 1998........ 18,685 $1,868 $119,303 $(9,682) $ 41,093 $ 1,525 $154,107
------ ------ -------- ------- -------- ------- --------

Reversal of unrealized gain on
available for sale
securities.................... -- -- -- -- -- (1,525) (1,525)
Foreign currency translation
adjustment, net of tax........ -- -- -- -- -- 9 9
Issuance of warrants with 14%
Notes......................... -- -- 7,434 -- -- -- 7,434
Issuance of common stock in
equity offering, net of
offering costs................ 64,245 6,425 174,016 -- -- -- 180,441
Issued to lender in lieu of
fee........................... 200 20 980 -- -- -- 1,000
Exercise of options............. 15 2 92 -- -- -- 94
Other........................... 10 2 (210) -- -- -- (208)
Net income (loss)............... -- -- -- -- (53,258) -- (53,258)
------ ------ -------- ------- -------- ------- --------
BALANCE AT JUNE 30, 1999........ 83,155 $8,317 $301,615 $(9,682) $(12,165) $ 9 $288,094
------ ------ -------- ------- -------- ------- --------

Foreign currency translation
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) $(31,124) $ 8 $382,887
====== ====== ======== ======= ======== ======= ========

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

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2000, 1999 AND 1998

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 1,400 well
service rigs and 1,200 oilfield trucks as of June 30, 2000. The Company provides
a complete range of well services to major and independent oil and natural gas
producing companies, including: rig-based well maintenance, workover,
completion, and recompletion services (including horizontal recompletions);
oilfield trucking; 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 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 73 land drilling rigs as of June 30, 2000. 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 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 and parts and supplies held for sale at the Company's
various retail supply stores, are valued at the lower of average cost or market.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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:

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

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%.

Effective July 1, 1998, the Company made certain changes in the estimated
useful lives of its well service rigs, increasing the lives from 17 years to 25
years. This change decreased the net loss for the twelve months ended June 30,
1999 by approximately $3,100,000 ($0.11 per share-basic). Had this change been
made effective July 1, 1997, the effect would have increased net income for the
fiscal year ended June 30, 1998 by $1,317,000 ($0.08 per share-basic). This
change was made to better reflect the expected utilization of these assets over
time, to better provide matching of revenues and expenses and to better reflect
the industry standard in regards to estimated useful lives of workover rigs.

Effective July 1, 1997 the Company changed its method of calculating
depreciation on its drilling rigs from the straight-line method to the
units-of-production method. 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 more appropriately reflects its financial
results by better matching revenues with expenses and to better reflect how the
assets are to be used over time. The effect of this change on net income for
fiscal 1998 was not material.

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 has adopted 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, including goodwill, on a yard-by-yard basis and
compares the estimated future cash flows of each yard to the yard's

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
net carrying value including allocable goodwill. The Company would record an
impairment, 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.
Since adoption of this statement no impairment losses have been required.

HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

The Company uses derivative financial instruments, primarily commodity
option contracts to reduce the exposure of its oil and gas producing operations
to changes in the market price of natural gas and crude oil and to fix the price
for natural gas and crude oil independently of the physical sale.

The financial instruments that the Company accounts for as hedging contracts
must meet the following criteria: the underlying asset or liability must expose
the Company to price risk that is not offset in another asset or liability, the
hedging contract must reduce that price risk, and the instrument must be
designated as a hedge at the inception of the contract and throughout the
contract period. In order to qualify as a hedge, there must be clear correlation
between changes in the fair value of the financial instrument and the fair value
of the underlying asset or liability such that changes in the market value of
the financial instrument will be offset by the effect of price rate changes on
the exposed items.

Premiums paid for commodity option contracts, which qualify as hedges, are
amortized to oil and 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 gas sales for the applicable periods.

In June 1998, the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
133"). SFAS 133 establishes accounting and reporting standards requiring that
every derivative instrument (including certain derivative instruments embedded
in other contracts) be recorded in the balance sheet as either an asset or
liability measured at its fair value. SFAS 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement. Companies must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting. SFAS 133
is effective for fiscal years beginning after June 15, 2000 and will be adopted
as of July 1, 2000 by the Company. SFAS 133 cannot be applied retroactively and
must be applied to (a) derivative instruments and (b) certain derivative
instruments embedded in hybrid contracts that were issued, acquired, or
substantively modified after December 31, 1997 (and, at the Company's election,
before January 1, 1998.) The oil and gas collars currently in place will be
marked to market through the income statement until such time as they are
documented as hedges.

COMPREHENSIVE INCOME

The Company adopted Statement of Financial Accounting Standards No. 130,
"Reporting Comprehensive Income" ("SFAS 130") effective July 1, 1998. 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.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

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

Net Goodwill, totaling $198.6 million and $205.4 million at June 30, 2000
and 1999, respectively, represents the cost in excess of fair value of the net
tangible and identifiable intangible assets acquired and liabilities assumed in
purchase transactions. Goodwill is being amortized on a straight-line basis over
periods ranging from ten to 25 years. Amortization of goodwill for fiscal 2000,
1999 and 1998 was $9,840,000, $9,202,000 and $1,442,000, respectively. The
carrying amount of unamortized goodwill is reviewed for potential impairment
loss whenever events or changes in circumstances indicate that the carrying
amount of goodwill may not be recoverable (see Property and Equipment above, for
further discussion).

DEFERRED COSTS

Deferred costs totaling $30,998,000 and $30,488,000 at June 30, 2000 and
1999, respectively, represent debt issuance costs and are recorded net of
accumulated amortization of $12,142,000 and $6,709,000 at June 30, 2000 and
1999, respectively. Deferred costs are amortized to interest expense using the
straight-line method over the life of each applicable debt instrument or as
related debt is retired. This method approximates the amortization which would
be recorded using the effective interest method. Amortization of deferred costs
totaled $5,176,000, $4,664,000 and $2,006,000 for fiscal 2000, 1999 and 1998,
respectively.

INCOME TAXES

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

The Company and its eligible subsidiaries file a consolidated U.S. federal
income tax return. Certain subsidiaries that are consolidated for financial
reporting purposes are not eligible to be included in the consolidated U.S.
federal income tax return and separate provisions for income taxes have been
determined for these entities or groups of entities.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
EARNINGS PER SHARE

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

YEAR ENDED JUNE 30,
------------------------------------
2000 1999 1998
---------- ---------- ----------
(THOUSANDS, EXCEPT PER SHARE DATA)

BASIC EPS COMPUTATION:
NUMERATOR
Income (loss) before extraordinary gain................... $(20,570) $(53,258) $24,175
Extraordinary gain, net of tax............................ 1,611 -- --
-------- -------- -------
Net income (loss)......................................... $(18,959) $(53,258) $24,175
======== ======== =======
DENOMINATOR
Weighted average common shares outstanding................ 83,815 27,501 17,153
-------- -------- -------
BASIC EPS:
Before extraordinary gain................................. $ (0.25) $ (1.94) $ 1.41
Extraordinary gain, net of tax............................ 0.02 -- --
-------- -------- -------
After extraordinary gain.................................... $ (0.23) $ (1.94) $ 1.41
======== ======== =======
DILUTED EPS COMPUTATION:
NUMERATOR
Income (loss) before extraordinary gain................... $(20,570) $(53,258) $24,175
Effect of dilutive securities, tax effected:
Convertible securities.................................... -- -- 5,331
-------- -------- -------
Income (loss) before extraordinary gain................. $(20,570) $(53,258) $29,506
Extraordinary gain, net of tax.......................... 1,611 -- --
-------- -------- -------
Net income (loss)....................................... $(18,959) $(53,258) $29,506
======== ======== =======
DENOMINATOR
Weighted average common shares outstanding:............... 83,815 27,501 17,153
Warrants.................................................. -- -- 141
Stock options............................................. -- -- 1,266
7% Convertible Debentures................................. -- -- 1,191
5% Convertible Notes...................................... -- -- 4,273
-------- -------- -------
83,815 27,501 24,024

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

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

YEAR ENDED JUNE 30,
------------------------------------
2000 1999 1998
---------- ---------- ----------
(THOUSANDS, EXCEPT PER SHARE DATA)

DILUTED EPS:
Before extraordinary gain................................. $ (0.25) $ (1.94) $ 1.23
Extraordinary gain, net of tax............................ 0.02 -- --
-------- -------- -------
After extraordinary gain.................................. $ (0.23) $ (1.94) $ 1.23
======== ======== =======

The fiscal 2000 and 1999 earnings per share calculations exclude the
Company's convertible debt, outstanding warrants and stock options, because the
effects of such instruments on earning per share would be anti-dilutive.

CONCENTRATION OF CREDIT RISK

Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist primarily of temporary cash investments
and trade receivables. The Company restricts investment of temporary cash
investments to financial institutions with high credit standing and, by policy,
limits the amount of credit exposure to any one financial institution. The
Company's customer base primarily consists of multi-national, foreign 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, accounts receivable 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.

The Company did not have any one customer who represented 10% or more of
consolidated revenues for the fiscal year ended June 30, 2000 or 1999.

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.

In October 1995, the FASB issued Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock-Based Compensation", which sets forth
alternative accounting and disclosure requirements for stock-based compensation
arrangements. SFAS 123 does not rescind the existing accounting for employee
stock-based compensation under APB 25. Companies may continue to follow the
current

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
accounting 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 10 the pro forma information
required under SFAS 123.

FOREIGN CURRENCY GAINS AND LOSSES

The local currency is the functional currency for all of the Company's
foreign operations (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 equity until a partial or complete sale
or liquidation of the Company's net investment in the foreign entity.

CASH AND CASH EQUIVALENTS

The Company considers all unrestricted highly liquid investments with less
than a three-month maturity when purchased, as cash equivalents.

RECLASSIFICATIONS

Certain reclassifications have been made to the fiscal 1999 and 1998
consolidated financial statements to conform to the fiscal 2000 presentation.

2. RESTRUCTURING CHARGE

In response to an industry downturn caused by historically low oil and gas
prices and the resulting slowdown in business, on December 7, 1998, the Company
announced a company-wide restructuring plan to reduce operating costs beyond
those achieved through the Company's consolidation efforts. The plan involved a
reduction in the size of management and on-site work force, salary reductions
averaging 21% for senior management, the combination of previously separate
operating divisions and the elimination of redundant overhead and facilities.
The restructuring plan resulted in pretax charges to earnings of approximately
$6.7 million in the second quarter ending December 31, 1998 and $1.5 million in
the third quarter ending March 31, 1999. However, due to an increase in oil and
gas prices beginning during the Company's fourth fiscal quarter, the Company
amended its restructuring plan to decrease the number of planned employee
terminations. Increased demand for the Company's services made such terminations
unnecessary and would have, in management's opinion, restricted the Company's
ability to provide services to its customers. Consequently, the Company did not
utilize approximately $3.7 million of the pretax charges. Essentially all of the
unutilized portion of the restructuring charge was reversed in the fourth
quarter ending June 30, 1999 resulting in a total pretax charge for the fiscal
year ended June 30, 1999 of approximately $4.5 million. The charges include
severance payments and other termination benefits for approximately 97
employees, lease commitments related to closed facilities and environmental
studies performed on closed yard locations.

The Company has completed the plan at June 30, 2000. There remained
approximately $180,000 for COBRA benefits to terminated employees and $53,000
for contractual payments to an employee at

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

2. RESTRUCTURING CHARGE (CONTINUED)
June 30, 1999. The major components of the restructuring charge and costs
incurred through June 30, 1999 were as follows:

COST INCURRED
RESTRUCTURING THROUGH JUNE 30, BALANCE AS OF
DESCRIPTION CHARGE 1999 JUNE 30, 1999
- ----------- ------------- ----------------- --------------
(IN THOUSANDS)

Severance/Employee costs............................. $4,457 $(4,224) $233
Lease commitments.................................... 27 (27) --
Environmental clean-up............................... 20 (20) --
------ ------- ----
Total................................................ $4,504 $(4,271) $233
====== ======= ====

3. BUSINESS AND PROPERTY ACQUISITIONS

DAWSON PRODUCTION SERVICES, INC.

In September 1998, the Company completed the acquisition of all of the
capital stock of Dawson Production Services, Inc. ("Dawson") for an aggregate
consideration of approximately $382.6 million, including approximately $207.1
million of cash paid for the Dawson stock and for transactional fees and
approximately $175.5 million of net liabilities assumed.

Expenditures for the Dawson acquisition, including acquisition costs, less
cash acquired were as follows (in thousands):

Fair value of assets acquired, including goodwill........... $ 409,722
Liabilities assumed......................................... (199,439)
Liabilities for employee termination costs and lease
termination costs......................................... (3,162)
---------
Cash paid, including acquisition related expenditures and
the cost of Dawson common stock previously held........... 207,121
Less: Cash acquired......................................... (27,008)
---------
Net cash used for the acquisition........................... $ 180,113
=========

At the time of the closing, Dawson owned approximately 527 well service
rigs, 200 oilfield trucks, and 21 production testing units in South Texas and
the Gulf Coast, East Texas and Louisiana, the Permian Basin of West Texas and
New Mexico, the Anadarko Basin of Texas and Oklahoma, California, and in the
inland waters of the Gulf of Mexico.

In connection with the Dawson acquisition, the Company recognized
liabilities for the estimated costs to involuntarily terminate employees of
Dawson and to exit certain activities of Dawson, primarily Dawson's lease
liability for its corporate offices. As of June 30, 1999, the Company had
completed its severance plan, terminating 44 former Dawson employees. At June
30, 1999, the Company had $592,000 accrued, representing the estimated lease
termination costs of Dawson's former corporate offices.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

3. BUSINESS AND PROPERTY ACQUISITIONS (CONTINUED)
OTHER FISCAL 1999 ACQUISITIONS

In addition to its acquisition of Dawson, the Company acquired the assets
and/or capital stock of six well servicing and contract drilling businesses
during fiscal 1999, increasing its rig and truck fleet by a total of
approximately 93 well service rigs, 4 drilling rigs and 185 oilfield trucks (and
related equipment) for an aggregate purchase price of approximately $93.7
million in cash. 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.

ACQUISITIONS COMPLETED PRIOR TO JUNE 30, 1998

During fiscal 1998, the Company purchased the capital stock of 17 companies
and purchased the assets of 13 other companies. The Company paid cash of
approximately $244 million, excluding purchase price adjustments, and issued
common stock and warrants to purchase the Company's common stock valued at
approximately $13.8 million. Each of the acquisitions was accounted for using
the purchase method and the results of operations of the acquisitions were
included in the Company's results of operations as of the date of completion of
each acquisition.

PRO FORMA RESULTS OF OPERATIONS--(UNAUDITED)

The following unaudited pro forma results of operations have been prepared
as though the Dawson acquisition and the significant fiscal 1998 acquisitions
(Ram Oil Well Service, Inc., Rowland Trucking Co., Inc., Big A Well Service Co.,
Sunco Trucking Co., Justis Supply Co., Inc., Dunbar Well Service, Inc., J.W.
Gibson Well Service Co., Updike Brothers, Inc. and Lakota Drilling Co.) had been
acquired on July 1, 1997 with adjustments to record specifically identifiable
decreases in direct costs and general and administrative expenses related to the
termination of individual employees. Pro forma amounts are not necessarily
indicative of the results that may be reported in the future.

YEAR ENDED JUNE 30,
-------------------
1999 1998
-------- --------

Revenue................................................. $524,924 $685,296
Net income (loss)....................................... (58,211) 13,164
Basic earnings (loss) per share......................... (2.12) 0.77

4. 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 1 to 3 years of the executive officer's base salary. The current
annual base salaries for the executive officers covered under such

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

4. COMMITMENTS AND CONTINGENCIES (CONTINUED)
employment agreements total approximately $1,125,000. The Company also enters
into employment agreements with other key employees as it deems necessary in
order to retain qualified personnel.

5. LONG-TERM DEBT

The components of long-term debt are as follows:

JUNE 30,
-------------------
2000 1999
-------- --------
(THOUSANDS)

Senior Credit Facility(i)
Revolving Loans....................................... $ 93,000 $ 90,000
Tranche A Term Loan................................... 22,987 43,366
Tranche B Term Loan................................... 175,961 177,761
14% Senior Subordinated Notes Due 2009(iii)............. 143,650 142,907
5% Convertible Subordinated Notes Due 2004(iv).......... 205,810 216,000
7% Convertible Subordinated Debentures Due 2003(v)...... 1,000 4,600
Dawson 9 3/8% Senior Notes Due 2007(vi)................. 1,106 1,406
Capital Leases.......................................... 21,911 20,306
Other notes payable..................................... 1,175 3,632
-------- --------
666,600 699,978
Less current portion.................................... 14,655 16,254
-------- --------
Long-term debt.......................................... $651,945 $683,724
======== ========

(I) SENIOR CREDIT FACILITY

On June 6, 1997, the Company entered into an agreement (the "Initial Credit
Agreement") with PNC Bank, N.A. ("PNC"), as administrative agent, and a
syndication of other lenders pursuant to which the lenders provided a
$255 million credit facility, consisting of a $120 million seven-year term loan
and a $135 million five-year revolver. The interest rate on the term loan was
LIBOR plus 2.75%. The interest rate on the revolver varied based on LIBOR and
the level of the Company's indebtedness. On September 25, 1997, the Company
repaid the term loan and a portion of the then outstanding amounts under the
revolver by applying the proceeds from the Company's private placement of the 5%
Convertible Subordinated Notes discussed below.

Effective November 6, 1997, the Company entered into an Amended and Restated
Credit Agreement (the "Amended Credit Agreement") with PNC, as administrative
agent and lender, pursuant to which PNC agreed to make revolving credit loans of
up to a maximum loan commitment of $200 million. Borrowings under the Amended
Credit Agreement were, at the Company's option, either (i) Eurodollar Loans with
interest payable quarterly at LIBOR plus 1.25%, (ii) Base Rate Loans with
interest payable quarterly at the greater of PNC Prime Rate or the Federal Funds
Effective Rate plus 0.50%, or (iii) a combination thereof. Effective
December 3, 1997, PNC completed the syndication of the Amended Credit Agreement.
In connection therewith, PNC, as administrative agent, a syndication of lenders
and the Company entered

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

5. LONG-TERM DEBT (CONTINUED)
into a First Amendment to the Amended Credit Agreement providing for, among
other things, an increase in the maximum commitment to $250 million from
$200 million.

The terms of the Amended Credit Agreement remained unchanged until the
Company's acquisition of Dawson in September 1998. In connection with the
acquisition of Dawson, the Company entered into a $550,000,000 Second Amended
and Restated Credit Agreement, dated as of June 6, 1997, as amended and restated
through September 14, 1998, among the Company, PNC Bank, National Association,
as Administrative Agent, Norwest Bank Texas, N.A., as Collateral Agent, PNC
Capital Markets, Inc., as Arranger, and the other lenders named from time to
time parties thereto (as subsequently amended, the "Current Credit Agreement").

The Current Credit Agreement provides for a senior credit facility
consisting of $150 million in revolving loans, $150 million in Tranche A term
loans and $200 million in Tranche B term loans. Amounts paid on the term loans
cannot be reborrowed. In addition, up to $20 million of letters of credit can be
issued under the Current Credit Agreement, but any outstanding letters of credit
reduces borrowing availability under the revolving loans. The Tranche A term
loans mature in sixteen consecutive quarterly installments commencing
December 14, 1999 with quarterly installment amounts equal to the applicable
percentage for a particular quarter multiplied by the unamortized principal
amount: 4% for installments 1-4, 6% for installments 5-8, 7% for installments
9-12 and 8% for installments 13-16. The Tranche B term loans mature in nineteen
consecutive quarterly installments commencing December 14, 1999 with quarterly
installment amounts equal to the applicable percentage for a particular quarter
multiplied by the unamortized principal amount: 0.25% for installments 1-16, 24%
for installments 17-18 and 48% for the final installment. The commitment to make
revolving loans will be reduced to $125 million and $100 million, on
September 14, 2001 and September 14, 2002, respectively. The revolving
commitment will terminate on September 14, 2003, and all the revolving loans
must be paid on or before that date.

The Current Credit Agreement contains various financial covenants,
including: (i) consolidated debt-to-capitalization ratio at generally decreasing
levels varying between 79% and 65%, (ii) consolidated interest coverage ratio at
generally increasing levels varying between 2.00-to-1.00 and 3.50-to-1.00,
(iii) consolidated senior leverage ratio at generally decreasing levels varying
between 2.50-to-1.00 and 2.00-to-1.00, and (iv) trailing 12-month EBITDA, as
adjusted, at generally increasing levels varying between $50 million and $150
million. In addition, the Company must maintain a consolidated fixed charge
coverage ratio at generally decreasing levels varying between 1.25-to-1.00 and
1.00 to 1.00. The covenants for consolidated senior leverage ratio and
consolidated interest coverage ratio are not imposed until the quarter ending
March 31, 2001, and the covenant levels for consolidated debt-to-capitalization
and trailing 12-month EBITDA, as adjusted, will remain fixed at 79% and
$50 million, respectively, for the same period. The Company is also required to
maintain a consolidated liquidity level of at least $30 million.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

5. LONG-TERM DEBT (CONTINUED)
The Current Credit Agreement 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
sell assets, to make dividends, purchases of our stock or subordinated debt, to
make capital expenditures in excess of levels ranging from $37.5 million in
fiscal 1999 to $65 million in fiscal 2004, or to make investments, loans and
advances or changes to debt instruments and organizational documents. The
Company will not be permitted to make acquisitions unless (i) its consolidated
debt to capitalization ratio is not more than 60% or (ii) its consolidated debt
to capitalization ratio is not increased and the acquisition is funded solely
with capital stock. The Company must also maintain consolidated net worth not
less than $195 million plus (i) 75% of consolidated net income for each fiscal
quarter beginning with the period ending December 31, 1998, (ii) 75% of the net
cash proceeds from issuance of capital stock after September 14, 1998 and
(iii) 75% of the increase in consolidated net worth resulting from the
conversion of the 5% Convertible Subordinated Notes or other convertible debt
issued after September 14, 1998. All obligations under the senior credit
facility are guaranteed by most of the Company's subsidiaries and are secured by
substantially all the Company's assets, including the Company's accounts
receivable, inventory and equipment. Unless required percentages of the lenders
otherwise agree, the term loans under the Current Credit Agreement, must be
prepaid from 75% of the Company's excess cash flow (as defined) for each fiscal
year until the Company's debt-to capitalization ratio (as defined) is less than
60% and 50% of the Company's excess cash flow for each fiscal year thereafter.

At June 30, 1999, the principal amount outstanding under the Tranche A term
loan the Tranche B term loan and the revolver was $43.4 million, $177.8 million
and $89.6 million, respectively. During fiscal 2000, the Company repaid
approximately $22.2 million under the term loans while increasing net borrowings
under the revolver by $3 million. As a result, at June 30, 2000, the principal
amount outstanding under the Tranche A term loan, the Tranche B term loan and
the revolver was reduced to approximately $23.0, $176.0 million and
$93.0 million, respectively. Additionally, the Company had outstanding letters
of credit of $15,132,000 and $10,832,000 as of June 30, 2000 and 1999,
respectively, related to its workman's compensation insurance.

Since June 30, 2000, a portion of the net proceeds from the Company's equity
offering (see Note 10) was used to repay the entire outstanding balance of the
Tranche A term loan and $2.3 million of the Tranche B term loan thereby reducing
the principal amount outstanding under the Tranche B term loan to approximately
$174 million. The Tranche B term loan prepayments were applied to reduce each of
the mandatory repayment installments of the Tranche B term loan pro rata,
thereby equally reducing all amortization payments without altering the
amortization schedule. In addition, $65 million of the net proceeds from the
Equity Offering were used to reduce the principal amount outstanding under the
revolver to $28 million. The remainder of the net proceeds of the Equity
Offering was used to retire other long-term debt. In addition, the principal
amount outstanding under the revolver has been further reduced to $23 million as
of September 28, 2000.

(II) BRIDGE LOAN

In connection with the Dawson acquisition, the Company entered into a bridge
loan agreement in the amount of $150,000,000, dated as of September 14, 1998,
among the Company, Lehman Brothers Inc., as Arranger, and Lehman Commercial
Paper Inc., as Administrative Agent, and the other lenders party thereto (the
"Bridge Loan Agreement"). Interest under the Bridge Loan Agreement accrued at
LIBOR

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

5. LONG-TERM DEBT (CONTINUED)
plus 6.50% and was payable on the 16th day of each month beginning October 16,
1998. The Bridge Loan was repaid in January 1999 with proceeds from the
Company's issuance of the 14% Senior Subordinated Notes.

(III) 14% SENIOR SUBORDINATED NOTES

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
may redeem up to 35% of the aggregate principal amount of the 14% Senior
Subordinated Notes with the proceeds of certain offerings of equity at 114% of
par, plus accrued interest.

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, as defined in the
indenture under which the 14% Senior Subordinated Notes were issued, includes
borrowings under the Current Credit Agreement and the Dawson 9 3/8% Senior
Notes.

In the event of a change in control of the Company, as defined in the
indenture under which the 14% Senior Subordinated Notes were issued, each holder
of 14% Senior Subordinated Notes will have the right, at the holder's option, to
require the Company to repurchase all or any part of the holder's 14% Senior
Subordinated Notes, within 60 days of such event, at a price equal to 100% of
the principal amount thereof, together with accrued and unpaid interest thereon.

At June 30, 2000, $150,000,000 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, beginning
July 15, 1999. Interest of approximately $10,092,000 was paid on July 15, 1999
and $10,500,000 was paid on January 15, 2000. As of June 30, 2000, 52,000 Unit
Warrants had been exercised, producing approximately $3,700,000 of proceeds to
the Company and leaving 98,000 Unit Warrants outstanding.

(IV) 5% CONVERTIBLE SUBORDINATED NOTES

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

5. LONG-TERM DEBT (CONTINUED)
additional $16 million of the 5% Convertible Subordinated Notes pursuant to the
exercise of the remaining portion of the over-allotment option granted to the
initial purchasers of the 5% Convertible Subordinated Notes. The placements were
made as private offerings pursuant to Rule 144A and Regulation S under the
Securities Act. The 5% Convertible Subordinated Notes are subordinate to the
Company's senior indebtedness, which, as defined in the indenture under which
the 5% Convertible Subordinated Notes were issued, includes borrowings under the
Current Credit Agreement, the 14% Senior Subordinated Notes and the Dawson
9 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.

In the event of a change in control of the Company, as defined in the
indenture under which the Notes were issued, each holder of 5% Convertible
Subordinated Notes will have the right, at the holder's option, to require the
Company to repurchase all or any part of the holder's 5% Convertible
Subordinated Notes, within 60 days of such event, at a price equal to 100% of
the principal amount thereof, together with accrued and unpaid interest thereon.

During the quarter ended June 30, 2000, the Company repurchased (and
canceled) $10,190,000 principal amount of the 5% Convertible Subordinated Notes,
leaving $205,810,000 principal amount of the 5% Convertible Subordinated Notes
outstanding at June 30, 2000. This repurchase resulted in an after-tax gain of
$1,611,000. Since June 30, 2000, the Company repurchased (and canceled)
$10,196,000 principal amount of the 5% Convertible Subordinated Notes leaving
$195,614,000 outstanding as of September 28, 2000. Interest on the 5%
Convertible Subordinated Notes is payable on March 15 and September 15. Interest
of approximately $5.4 million was paid on September 15, 1999 and March 15, 2000.

(V) 7% CONVERTIBLE SUBORDINATE DEBENTURES

In July 1996, the Company completed a $52,000,000 private placement of 7%
Convertible Subordinated Debentures due 2003 (the "7% Convertible Subordinated
Debentures") pursuant to Rule 144A under the Securities Act. The 7% Convertible
Subordinated Debentures are subordinate to the Company's senior indebtedness,
which, as defined in the indenture under which the 7% Convertible Subordinated
Debentures were issued, includes borrowings under the Current Credit Agreement,
the 14% Senior Subordinated Notes and the Dawson 9 3/8% Senior Notes.

The 7% Convertible Subordinated Debentures are redeemable, at the option of
the Company, on or after July 15, 1999, at a redemption price of 104%,
decreasing 1% per year on each anniversary date thereafter. In the event of a
change in control of the Company, as defined in the indenture under which the

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

5. LONG-TERM DEBT (CONTINUED)
7% Convertible Subordinated Debentures were issued, each holder will have the
right, at the holder's option, to require the Company to repurchase all or any
part of the holder's 7% Convertible Subordinated Debentures within 60 days of
such event at a price equal to 100% of the principal amount thereof, together
with accrued and unpaid interest thereon.

During fiscal 1998, $47,400,000 in principal amount of the Debentures was
converted into 4,861,538 shares of the Company's common stock. An additional
165,423 shares of common stock were issued representing 50% of the interest
otherwise payable from the date of conversion through July 1, 1999 and an
additional 35,408 shares of common stock were issued as an inducement to
convert. The additional 165,423 shares of common stock, representing 50% of the
interest otherwise payable from the date of conversion through July 1, 1999, are
included in equity. The fair value of the additional 35,408 shares of common
stock issued as inducement to convert was $710,186 and is recorded as interest
expense in the consolidated statement of operations. In addition, the
proportional amount of unamortized debt issuance costs associated with the
converted 7% Convertible Subordinated Debentures was charged to additional
paid-in capital at the time of conversion.

During fiscal 2000, $3,600,000 in principal amount of the Debentures was
converted into 369,229 shares of the Company's common stock. An additional
11,261 shares of common stock were issued representing 100% of the interest
otherwise payable from January 1, 2000 through July 1, 2000.

The additional 11,261 shares of common stock, representing 100% of the
interest otherwise payable from January 1, 2000 through July 1, 2000, are
included in equity. In addition, the proportional amount of unamortized debt
issuance costs associated with the converted 7% Convertible Subordinated
Debentures was charged to additional paid-in capital at the time of conversion.

At June 30, 2000, $1,000,000 principal amount of the 7% Convertible
Subordinated Debentures remained outstanding. On August 31, 2000, $985,000
principal amount of the 7% Convertible Subordinated Debentures were surrendered
for conversion by the holders thereof and 101,025 shares of common stock were
issued on September 1, 2000. The remaining $15,000 principal amount of the
outstanding 7% Convertible Subordinated Debentures were redeemed at 103% of the
principal amount plus accrued interest leaving none outstanding as of
September 28, 2000. Interest on the 7% Convertible Subordinated Debentures was
payable on January 1 and July 1 of each year. Interest of approximately $161,000
was paid on July 1, 1999 and January 1, 2000.

(VI) DAWSON 9 3/8% SENIOR NOTES

As the result of the Dawson acquisition (see Note 3), the Company, its
subsidiaries and U.S. Trust Company of Texas, N.A., trustee ("U.S. Trust"),
entered into a Supplemental Indenture dated September 21, 1998 (the
"Supplemental Indenture"), pursuant to which the Company assumed the obligations
of Dawson under the Indenture dated February 20, 1997 (the "Dawson Indenture")
between Dawson and U.S. Trust. Most of the Company's subsidiaries guaranteed
those obligations and the senior notes due 2007 (the "Dawson 9 3/8% Senior
Notes") issued pursuant to the Dawson Indenture were equally and ratably secured
with the obligations under the Current Credit Agreement. On November 17, 1998
the Company completed a cash tender offer to purchase the full $140,000,000
outstanding principal amount of Dawson 9 3/8% Senior Notes at 101% of the
aggregate principal amount of the notes, using borrowings under the Current
Credit Agreement. Under the tender offer, $138,594,000 in principal amount of
the Dawson 9 3/8%

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

5. LONG-TERM DEBT (CONTINUED)
Senior Notes was redeemed and a premium of $1,386,000 was paid. In addition,
accrued interest of $4,078,000 was paid at redemption.

At June 30, 1999, $1,406,000 principal amount of the Dawson 9 3/8% Senior
Notes remained outstanding. During the quarter ended June 30, 2000, the Company
repurchased $300,000 principal amount of the Dawson 9 3/8% Senior Notes, leaving
$1,106,000 principal amount of the Dawson 9 3/8% Senior Notes remained
outstanding at June 30, 2000. Since June 30, 2000, the Company repurchased
$800,000 principal amount of the Dawson 9 3/8% Senior Notes, leaving $306,000
principal amount outstanding as of September 28, 2000. Interest on the Dawson
9 3/8% Senior Notes is payable on February 1 and August 1 of each year. Interest
of approximately $65,906 was paid on August 1, 1999 and February 1, 2000.

CAPITALIZED EXPENSES, REPAYMENT SCHEDULE AND INTEREST EXPENSE

The Company capitalized a total of approximately $16,370,000 in fees and
expenses in connection with its various financings during fiscal 1999.

Presented below is a schedule of the repayment requirements of long-term
debt for each of the next five years and thereafter as of June 30, 2000:

PRINCIPAL
FISCAL YEAR ENDED AMOUNT
- ----------------- --------------
(IN THOUSANDS)

2001........................................................ $ 14,655
2002........................................................ 15,687
2003........................................................ 16,732
2004........................................................ 172,988
2005........................................................ 205,067
Thereafter.................................................. 241,471
--------
$666,600
========

The Company's interest expense for the years ended June 30, 2000, 1999 and
1998 consist of the following:

2000 1999 1998
-------- -------- --------
(IN THOUSANDS)

Cash Payments for interest....................... $61,956 $52,397 $16,441
Commitment & agency fees paid.................... 1,139 527 860
Accretion of discount on notes................... 743 552 --
Amortization of capitalized loan payments........ 5,176 4,664 2,459
Net change in accruals........................... 2,916 9,261 1,716
------- ------- -------
$71,930 $67,401 $21,476
======= ======= =======

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

6. DEBT ISSUANCE COSTS

During fiscal 1999, the Company recorded an expense item of $6,307,000,
which represented the write-off of debt issuance costs. The debt issuance costs
were associated with the Bridge Loan Agreement, which was subsequently paid
primarily with the proceeds from the Company's private placement of 14% Senior
Subordinated Notes (see Note 5). During fiscal 2000, the Company expensed
$338,000 of debt issuance costs related to the conversion of 7% Notes and other
prepayments of debt.

7. 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, 2000 and 1999. 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.

2000 1999
------------------- -------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- -------- -------- --------

Financial Assets:
Cash & cash equivalents........................... $109,873 $109,873 $ 23,478 $ 23,478
Accounts receivable, net.......................... 123,203 123,203 91,998 91,998
Notes receivable--affiliate....................... 5,150 5,150 2,385 2,385
Commodity collar contracts........................ -- (778) 717 --
Financial Liabilities:
Accounts payable.................................. 34,091 34,091 18,527 18,527
Long-term debt
Senior Credit Facility.......................... 291,948 291,948 311,127 311,127
5% Convertible Subordinated Notes............... 205,810 160,532 216,000 137,160
7% Convertible Subordinated Debentures.......... 1,000 1,130 4,600 3,450
14% Senior Subordinated Notes................... 143,650 162,325 142,907 153,750
Dawson 9 3/8% Senior Notes...................... 1,106 1,029 1,406 1,336
Capital lease liabilities....................... 21,911 21,911 20,306 20,306
Other debt...................................... 1,175 1,175 3,632 3,632

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: The carrying amount of the commodity option
contracts is comprised of the unamortized premiums paid for the option
contracts. The fair value of the commodity option contracts is estimated using
the discounted forward prices of each options index price, for the term of each
option contract.

Notes receivable-affiliate: The amounts reported relate to notes receivable
from officers of the Company.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

7. FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED)
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, 2000
and 1999, and the carrying amounts outstanding under the Company's senior credit
facility.

8. 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
non-performance by the counter-parties to its commodity hedges. The Company only
deals with reputable financial institutions as counter-parties and anticipates
that such counter-parties will be able to fully satisfy their obligations under
the contracts. The Company does not obtain collateral or other security to
support financial instruments subject to credit risk but monitors the credit
standing of the counter-parties.

The Company utilizes option or collar contracts to hedge the effect of price
changes on future oil and gas production. The objective of its hedging
activities is to achieve more predictable revenues and cash flows. If market
prices of oil and gas exceeded the strike price of put options, the options
would expire unexercised, therefore reducing the effective price received for
oil and gas sales by the cost of the related option. If the strike price of put
options exceeds the market prices of oil and gas, the Company would receive
payment from the counter-party of the contract equal to the contracted volumes
times the difference between the market price and the strike price, increasing
the effective price received for oil and gas sales by the amount received from
the counter-party. If the market price of oil and gas is outside the "collar" on
collar contracts, the Company will pay or receive payment which will increase or
decrease the effective price received for oil and gas sales.

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 gas revenues for the year ended June 30, 2000 by $822,270 and increased oil
and gas revenues for the year ended June 30, 1999 by $158,500.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

8. DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED)
The following table sets forth the future volumes hedged by year and the
weighted-average strike price of the option contracts at June 30, 2000 and 1999:

MONTHLY INCOME
-------------------
OIL GAS STRIKE PRICE
(BBLS) (MMBTU) TERM PER BBL/MMBTU
-------- -------- --------------------- -------------

At June 30, 2000
Oil Collars........... 4,000 -- May 2000-Feb 2001 $22.20-$26.50
5,000 -- Mar 2001-Feb 2002 $19.70-$23.70
Gas Collars........... 30,000 May 2000-Feb 2001 $ 2.60-$3.19
40,000 Mar 2001-Feb 2002 $ 2.40-$2.91

At June 30, 1999
Oil................... 5,000 -- Jun 1999-May 2000 $ 17.00
Oil................... 17,000 -- Jul 1999-Jun 2000 $ 18.00
Gas................... -- 100,000 Jun 1999-May 2000 $ 2.50

(The strike prices for oil are based on the NYMEX spot price for West Texas
Intermediate; the strike prices for gas are based on the Inside FERC-West Texas
Waha spot price).

9. OTHER ACCRUED LIABILITIES

Other accrued liabilities consist of the following:

JUNE 30,
-------------------
2000 1999
-------- --------
(THOUSANDS)

Accrued payroll, taxes and employee benefits.............. $15,261 $15,423
State sales, use and other taxes.......................... 2,465 2,044
Oil and gas revenue distribution.......................... 1,714 267
Other..................................................... 6,958 7,557
------- -------
Total..................................................... $26,398 $25,291
======= =======

10. STOCKHOLDERS' EQUITY

EQUITY OFFERINGS

On June 30, 2000, the Company closed the public offering of 11,000,000
shares of common at $9.625 per share, or approximately $106 million (the "Equity
Offering"). Net proceeds from the 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 to retire other long-term
debt.

On May 7, 1999, the Company closed the public offering of 55,300,000 shares
of common stock (300,000 shares of which were sold pursuant to the underwriters'
over-allotment option discussed below) at $3.00 per share, or $166 million (the
"Prior Public Offering"). Concurrently therewith, the Company closed the
offering of an additional 3,508,772 shares of common stock at $2.85 per share,
or $10 million

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

10. STOCKHOLDERS' EQUITY (CONTINUED)
(the "Prior Concurrent Offering" and together with the Prior Public Offering,
the "Prior Equity Offerings"). In addition, on June 7, 1999, the underwriters of
the Prior Public Offering exercised an over-allotment option to purchase an
additional 5,436,000 million shares to cover over-allotments. Net proceeds from
the Prior Equity Offerings of approximately $180.4 million were used to repay a
portion of the Company's term loan borrowings under its senior credit facility.

STOCK INCENTIVE PLANS

On January 13, 1998 the Company's shareholders approved the Key Energy
Group, Inc. 1997 Incentive Plan, as subsequently 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
offering discussed above, as of June 30, 2000, the number of shares of the
Company's common stock that may be covered by Incentive Awards has increased to
approximately 9.68 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 Awards. 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.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

10. STOCKHOLDERS' EQUITY (CONTINUED)
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 (ie., generally the chief executive officer
and the other four most highly compensated executives for a given year.)

The 1997 Incentive Plan is administrated by the Compensation Committee
appointed by the Board of Directors (the "Committee") consisting of not less
than two directors each of whom is (i) an "outside director" under
Section 162(m) of the Code and (ii) a "non-employee director" under Rule 16b-3
of the Securities Exchange Act of 1934. In addition, subject to applicable
shareholder approval requirements, the Company may issue NSOs outside the 1997
Incentive Plan.

The exercise price of options issued under the 1997 Incentive Plan and
outside the 1997 Incentive Plan is 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):

FISCAL YEAR ENDING JUNE 30,
------------------------------------------------------------------
2000 1999 1998
-------------------- -------------------- --------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
-------- --------- -------- --------- -------- ---------

Outstanding--beginning of fiscal year..... 6,920 $ 5.55 2,292 $10.33 2,086 $ 8.13
Granted................................. 3,688 8.61 5,443 4.32 415 18.65
Exercised............................... (241) 4.56 (15) 6.36 (209) 5.00
Forfeited............................... (897) 9.80 (800) 10.87 -- --
----- ----- -----
Outstanding, June 30...................... 9,470 6.37 6,920 5.55 2,292 10.33
===== ===== =====
Exercisable--end of fiscal year........... 4,370 1,020 672
===== ===== =====

The foregoing stock option activity summary reflects that effective as of
September 4, 1998, the Committee authorized the cancellation and reissue of
stock options for employees that were not executive offices for the purpose of
changing the exercise price and vesting schedule of such options. A total of
473,556 stock options were cancelled, with a weighted average price of
approximately $13.09 per share, and reissued with an exercise price of $7.125
per share. The vesting of the new options is ratable over a three-year period
from the date of grant.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

10. STOCKHOLDERS' EQUITY (CONTINUED)
The following table summarizes information about the stock options
outstanding at June 30, 2000 (shares in thousands):

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------------- --------------------------
NUMBER OF WEIGHTED- WEIGHTED- NUMBER OF WEIGHTED-
SHARES AVERAGE AVERAGE SHARES AVERAGE
OUTSTANDING AT REMAINING EXERCISE EXERCISABLE AT EXERCISE
RANGE OF EXERCISE PRICES JUNE 30, 2000 CONTRACTUAL LIFE PRICE JUNE 30, 2000 PRICE
- ------------------------ -------------- ---------------- --------- -------------- ---------

$3.00 - $5.00 4,112 7.51 $ 3.28 2,639 $ 3.54
$6.00 - $6.8125 90 9.00 6.63 -- --
$7.125 - $8.375 1,382 7.75 7.28 778 7.39
$8.50 - $9.50 3,510 9.00 8.76 578 9.27
$11.125 - $20.50 375 6.00 13.25 375 13.25

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 per share would have been
reduced to pro forma amounts indicated below:

2000 1999 1998
-------- -------- --------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)

Net income (loss):
As reported.......................................... $(18,959) $(53,258) $24,175
Pro forma............................................ (25,684) (57,057) 22,343

Earnings per share of common stock:
As reported.......................................... $ (0.23) $ (1.94) $ 1.41
Pro forma............................................ (0.31) (2.07) 1.31

Earnings per share of common stock--assuming
Dilution:
As reported.......................................... $ (0.23) $ (1.94) $ 1.23
Pro forma............................................ $ (0.31) (2.07) 1.14

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.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

10. STOCKHOLDERS' EQUITY (CONTINUED)
The total fair value of stock options granted during 2000, 1999 and 1998 was
$19,541,000, $15,695,000 and $7,994,000, 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.

YEAR OF GRANT
------------------------------
2000 1999 1998
-------- -------- --------

Risk-free interest rate................................... 6.40% 5.09% 5.79%
Expected life of options.................................. 5 years 5 years 5 years
Expected volatility of the Company's stock price.......... 67% 98% 136%
Expected dividends........................................ none none none

11. INCOME TAXES

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

FISCAL YEAR ENDED JUNE 30,
------------------------------
2000 1999 1998
-------- -------- --------
(THOUSANDS)

Federal and State:
Current....................................... $(5,588) $ -- $ 7,343
Deferred......................................
U.S......................................... (1,818) (25,560) 7,287
Foreign..................................... -- (115) --
------- -------- -------
$(7,406) $(25,675) $14,630
======= ======== =======

The Company paid $9,024,000 for income taxes in fiscal 1998. No income tax
payments were made for fiscal 2000 or 1999.

Income tax expense (benefit) from continuing operations differs from amounts
computed by applying the statutory federal rate as follows:

FISCAL YEAR ENDED JUNE 30,
------------------------------------
2000 1999 1998
-------- -------- --------
(THOUSANDS)

Income tax computed at statutory rate................. (35.0)% (35.0)% 35.0%
Amortization of goodwill disallowance................. 7.0 2.0 1.1
Meals and entertainment disallowance.................. 1.3 0.3 0.7
State taxes........................................... 0.0 0.0 0.7
Change in valuation allowance and other............... 0.2 0.2 0.2
----- ----- ----
(26.5)% (32.5)% 37.7%
===== ===== ====

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

11. INCOME TAXES (CONTINUED)
Deferred tax assets (liabilities) are comprised of the following:

FISCAL YEAR ENDED
JUNE 30,
---------------------
2000 1999
--------- ---------
(THOUSANDS)

Net operating loss and tax credit carry forwards...... $ 88,491 $ 97,689
Property and equipment................................ (175,511) (163,594)
Self insurance reserves............................... 1,616 1,578
Allowance for bad debts............................... 1,129 2,612
Acquisition expenses, expensed for tax................ (626) (4,773)
Other................................................. 862 112
--------- ---------
Net deferred tax liability............................ (84,039) (66,376)
Valuation allowance of deferred tax assets............ (15,668) (35,054)
--------- ---------
Net deferred tax liability, net of valuation
allowance........................................... $ (99,707) $(101,430)
========= =========

A valuation allowance is provided when it is more likely than not that some
portion of the deferred tax assets will not be realized. Due to uncertainties
arising from a lack of earnings history and based on management's future
expectations, it does not appear more likely than not that the Company will be
able to utilize all the available carryforwards prior to their ultimate
expiration.

The Company estimates that as of June 30, 2000, the Company will have
available approximately $249,253,000 of net operating loss carryforwards (which
begin to expire in fiscal 2001). Approximately $51,272,000 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.

12. LEASING ARRANGEMENTS

The Company leases certain property and equipment under non-cancelable
operating leases that generally expire at various dates through fiscal 2002. The
term of the operating leases generally run from 24 to 60 months with varying
payment dates throughout each month.

As of June 30, 2000 the future minimum lease payments under non-cancelable
operating leases are as follows (in thousands):

LEASE
FISCAL YEAR ENDING JUNE 30, PAYMENTS
- --------------------------- --------

2001............................................... $2,221
2002............................................... 1,555
2003............................................... 1,209
2004............................................... 1,147
2005............................................... 1,110
------
$7,242
======

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

12. LEASING ARRANGEMENTS (CONTINUED)
Operating lease expense was approximately $6,459,698, $7,313,000 and
$8,002,000, for the fiscal years ended June 30, 2000, 1999 and 1998,
respectively.

13. 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, with such contributions
totaling $907,509. From January 1, 1999 to 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 Company's matching contributions for fiscal
2000 and 1999 were $77,000 and $907,509, respectively.

14. TRANSACTIONS WITH RELATED PARTIES

In connection with the negotiation of the terms of a five-year employment
agreement with Mr. Francis D. John, Chairman of the Board, President and Chief
Executive Officer of the Company, and as an inducement to Mr. John to enter into
such employment agreement, the Company entered into a separate agreement with
Mr. John, dated as of August 2, 1999, which as amended through June 30, 2000,
provides that $5 million in loans previously made by the Company to Mr. John,
together with the accrued interest payable thereon, will be forgiven ratably
during the ten year period commencing on July 1, 2001 and ending on June 30,
2010. The agreement provides that the foregoing forgiveness of indebtedness is
predicated and conditioned upon Mr. John remaining employed by the Company
during such period. In addition, in the event that Mr. John is terminated by the
Company for "Cause" (as defined in the agreement), or in the event that
Mr. John voluntarily terminates his employment with the Company, the agreement
further provides that the entire remaining principal balance of these loans,
together with accrued interest payable thereon, will become immediately due and
payable by Mr. John. However, in the event that Mr. John's employment is
terminated for "Good Reason", or as a result of Mr. John's death or
"Disability", or as a result of a "Change in Control" (all as defined in that
agreement), the agreement stipulates that the remaining principal balance
outstanding on the loans, together with accrued interest thereon will be
forgiven.

During fiscal 1998, Metretek Technologies, a diversified provider of
products and services to the natural gas industry and a company for which W.
Phillip Marcum, one of the Directors of the Company, serves as Chairman of the
Board, President and Chief Executive Officer, sold certain assets held by its
wholly owned subsidiary, Marcum Gas Transmission, to Odessa. Metretek
Technologies sold the assets for a total consideration of $700,000. Metretek
Technologies also granted Odessa a right of first refusal to participate in
future projects developed by Marcum Gas Transmission on terms and conditions
identical to those provided in future projects developed by Marcum Gas
Transmission on terms and conditions identical to those provided to Marcum Gas
Transmission.

During fiscal 1998, the Company deposited $250,000 in money market account
as collateral to secure a bank loan made to a business entity in which Danny R.
Evatt, then the Chief Information Officer and Vice President of Financial
Operations of the Company, owns an interest. Such amount was returned to the
Company during fiscal 2000.

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

14. TRANSACTIONS WITH RELATED PARTIES (CONTINUED)
In fiscal 1999, an investment management firm in which David J. Breazzano,
one of the Company's directors, is a principal, purchased $25 million principal
amount of the Company's borrowings under a bridge loan agreement which has since
been repaid in full.

In fiscal 1999, the Company entered into a consulting agreement with an
investment banking firm in which Kevin P. Collins, one of the Company's
directors, is a principal, pursuant to which such firm provided financial
advisory services to the Company in connection with equity offering completed in
fiscal 1999 and for which such firm received a total of $167,000.

In connection with the negotiation of an employment agreement with Thomas K.
Grundman, the Company's Executive Vice President of International Operations,
Chief Financial Officer, Chief Accounting Officer and Treasurer, the Company
made a $240,000 short-term loan and a $150,000 relocation loan to assist
Mr. Grundman's relocation to the Company's executive offices. Interest on these
loans accrues at a rate of 6.125% per annum. The short-term loan has been
repaid. The relocation loan together with accrued interest will be forgiven in
three installments of $50,000 each on July 1, 2000, 2001 and 2002; PROVIDED,
HOWEVER, that if Mr. Grundman's employment is terminated during such period in a
way that (i) triggers severance obligations, all amounts owed shall be
immediately forgiven or (ii) does not trigger severance obligations, all amounts
owed shall be immediately due and payable.

15. BUSINESS SEGMENT INFORMATION

The Company operates in three business segments: well servicing, contract
drilling and oil and natural gas production.

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.

Oil and Natural Gas Production: The Company produces crude oil and natural
gas, in the Permian Basin and Panhandle areas of West Texas. 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

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

15. BUSINESS SEGMENT INFORMATION (CONTINUED)
segments. Corporate assets consist principally of cash and cash equivalents,
deferred debt financing costs and deferred income tax assets.

WELL CONTRACT OIL AND NATURAL CORPORATE /
SERVICING DRILLING GAS PRODUCTION OTHER TOTAL
--------- -------- --------------- ----------- ----------

2000
Operating revenues.................. $559,492 $ 68,428 $ 9,391 $ 421 $ 637,732
Operating profit.................... 159,552 10,129 5,244 421 175,346
Depreciation, depletion and
amortization...................... 62,680 6,105 1,955 232 70,972
Interest expense.................... 2,300 -- -- 69,630 71,930
Net income (loss) before
extraordinary gain*............... 48,062 (1,664) 2,508 (69,476) (20,570)
Identifiable assets................. 635,304 89,574 35,682 287,072 1,047,632
Capital expenditures (excluding
acquisitions)..................... 30,098 8,282 917 2,505 41,802
1999
Operating revenues $433,657 $ 50,613 $ 6,461 $ 1,086 $ 491,817
Operating profit.................... 108,692 7,057 3,554 1,086 120,389
Depreciation, depletion and
amortization...................... 52,638 6,586 2,422 428 62,074
Interest expense.................... 1,659 18 -- 65,724 67,401
Net income (loss)*.................. 15,447 (4,093) 552 (65,164) (53,258)
Identifiable assets................. 651,781 81,074 36,707 173,153 942,715
Capital expenditures (excluding
acquisitions)..................... 26,776 1,063 287 3,181 31,307
1998
Operating revenues.................. $356,238 $ 58,199 $ 7,030 $ 3,076 $ 424,543
Operating profit.................... 108,633 15,339 4,047 3,076 131,095
Depreciation, depletion and
amortization...................... 24,334 4,176 2,043 448 31,001
Interest expense.................... 624 19 (13) 20,846 21,476
Net income (loss)*.................. 37,991 3,681 1,115 (18,612) 24,175
Identifiable assets................. 352,014 109,873 37,265 154,552 653,704
Capital expenditures (excluding
acquisitions)..................... 44,284 5,385 7,849 1,748 59,266

- ------------------------

* Net income (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 $37.2 million and
$5.3 million, respectively, for the year ended June 30, 2000. Operating revenues
and operating profit for the Company's foreign operations, which includes
Argentina and Canada, were $26.7 million and $5.2 million, respectively, for the
year ended June 30, 1999 and

KEY ENERGY SERVICES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

JUNE 30, 2000, 1999 AND 1998

15. BUSINESS SEGMENT INFORMATION (CONTINUED)
$32.5 million and $6.5 million, respectively, for the year ended June 30, 1998.
The Company had $66.9 million and $54.5 million of identifiable assets as of
June 30, 2000 and 1999, respectively, related to its foreign operations.

16. SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES

YEAR ENDED JUNE 30,
------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)

Fair value of common stock issued in purchase transaction... -- -- $ 13,863
Fair value of common stock issued to lender in lieu of
fees...................................................... -- 1 --
Fair value of common stock issued upon the conversion of
long-term
debt...................................................... 3,600 -- 100,826
Capital lease obligations................................... 10,758 17,120 --

17. UNAUDITED SUPPLEMENTARY INFORMATION--QUARTERLY RESULTS OF OPERATIONS

Summarized quarterly financial data for 2000 and 1999 are as follows:

FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

2000
Revenues............................................ $149,892 $159,389 $158,551 $169,900
Earnings (loss) from operations..................... (13,191) (7,953) (5,730) (1,102)
Net earnings (loss)................................. (9,451) (5,693) (4,150) (1,276)
Earnings per share.................................. (0.11) (0.07) (0.05) (0.01)
Weighted average common shares and equivalents
outstanding....................................... 82,738 82,738 84,633 85,567
1999
Revenues............................................ $115,587 $143,646 $104,923 $127,661
Earnings (loss) from operations..................... 3,157 (14,780) (48,153) (19,157)
Net earnings (loss)................................. 1,837 (9,797) (32,051) (13,247)
Earnings (loss) per share........................... 0.10 (0.54) (1.75) (0.24)
Weighted average common shares and equivalents
outstanding....................................... 18,268 18,291 18,293 55,245

18. VOLUMETRIC PRODUCTION PAYMENT

In March 2000, Key sold a part 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 Mmbtu 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.

INDEPENDENT AUDITORS' REPORT

To The Board of Directors
Key Energy Services, Inc. :

We have audited the accompanying consolidated balance sheets of Key Energy
Services, Inc. and subsidiaries as of June 30, 2000 and 1999, and the related
consolidated statements of operation, stockholders' equity and comprehensive
income, and cash flows for each of the years in the three-year period ended June
30, 2000. In connection with our audits of the consolidated financial
statements, we also have audited the financial statement schedule listed in the
Index at Item 14. 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 generally accepted auditing
standards. 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, 2000 and 1999, and the
results of their operations and their cash flows for each of the years in the
three-year period ended June 30, 2000, in conformity with generally accepted
accounting principles. 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.

KPMG LLP

Midland, Texas
August 31, 2000

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, 2000.

PART IV

ITEM 14. 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 As of and for
Each of the Three Years Ended June 30, 2000:
II--Consolidated Valuation and Qualifying
Accounts............................................ S-1

The supplemental schedules other than the one listed above are omitted
because of the absence of the conditions under which they are required or
because the required information is included in the Consolidated Financial
Statements or Notes thereto.

(3) Exhibits:

3.1 Amended and Restated Articles of Incorporation of the
Company. (Incorporated by reference to the Company's
Registration Statement on Form S-4, Registration No.
333-369).
3.2 Amended and Restated By-Laws of the Company. (Incorporated
by reference to the Company's Registration Statement on
Form S-4 dated March 8, 1996, Registration No. 333-369).
3.3 Amendment to the Amended and Restated Articles of
Incorporation of the Company. (Incorporated by reference
to Exhibit 3.1 of the Company's Current Report on Form 8-K
dated February 2, 1998, File No. 1-8038).
3.4 Amendment to the Amended and Restated Articles of
Incorporation of the Company. (Incorporated by reference
to Exhibit A of the definitive proxy statement on Schedule
14A filed by the Company on November 17, 1998, File No.
1-8038).
3.5 Articles of Amendment to Amended and Restated Articles of
Incorporation of the Company (Incorporated by reference to
Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q
for the quarter ended March 31, 2000, File No. 1-8038).
3.6 Unanimous Consent of the Board of Directors of the Company
dated January 11, 2000, limiting the designation of the
additional authorized shares to common stock (Incorporated
by reference to Exhibit 3.2 of the Company's Quarterly
Report on Form 10-Q for the quarter ended March 31, 2000,
File No. 1-8038).

4.1 7% Convertible Subordinated Debenture of the Company due
July 1, 2003. (Incorporated by reference to Exhibit 4.1 of
the Company's Annual Report on Form 10-K dated June 30,
1996, File No. 1-8038).
4.2 Indenture for the 7% Convertible Subordinated Debentures of
the Company due July 1, 2003. (Incorporated by reference
to Exhibit 4.2 of the Company's Annual Report on Form 10-K
dated June 30, 1996, File No. 1-8038).
4.3 First Supplemental Indenture dated as of November 20, 1996
by and between Key Energy Group, Inc. and American Stock
Transfer & Trust Company, as Trustee. (Incorporated by
reference to Exhibit 10(i) to the Company's Quarterly
Report on Form 10-Q dated December 31, 1996, File No.
1-8038).
4.4 Registration Rights Agreement among the Company, McMahan
Securities Co., L.P. and Rausher Pierce Refsnes, Inc.,
dated as of July 3, 1996. (Incorporated by reference to
Exhibit 4.3 of the Company's Annual Report on Form 10-K
dated June 30, 1996, File No. 1-8038).
4.5 Registration Rights Agreement dated as of March 2, 1996
among the Company and certain of its stockholders.
(Incorporated by reference to Exhibit 4.3 of the Company's
Registration Statement on Form S-4, Registration No.
333-369).
4.6 Form of Common Stock Purchase Warrant to Purchase Key Common
Stock issued in connection with the WellTech Merger.
(Incorporated by reference to Exhibit 4.1 of the Company's
Registration Statement on Form S-4, Registration No.
333-369).
4.7 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).
4.8 Registration Rights Agreement among Key Energy Group, Inc.,
Lehman Brothers Inc., and McMahan Securities Co. L.P.
dated as of September 25, 1997. (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).
4.9 Indenture dated February 20, 1997 between Dawson Production
Services, Inc. and U.S. Trust Company of Texas, N.A.
(Incorporated by reference to Exhibit 99.10 of the
Company's Current Report on Form 8-K dated September 28,
1998, File No. 1-8038).
4.10 Supplemental Indenture dated September 21, 1998, among Key
Energy Group, Inc., its Subsidiaries and U.S. Trust
Company of Texas, N.A. (Incorporated by reference to
Exhibit 99.11 of the Company's Current Report on Form 8-K
dated September 28, 1998, File No. 1-8038).
4.11 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).
4.12 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).
4.13 Registration Rights Agreement dated January 22, 1999 by and
among the Registrant, certain of its subsidiaries, and
Lehman Brothers, Inc., Bear, Stearns & Co. Inc.,
F.A.C./Equities, a division of First Albany Corporation,
and Dain Rauscher Wessels, a division of Dain Rauscher
Incorporated. (Incorporated by reference to Exhibit
99(d) of the Company's Form 8-K filed on February 3, 1999,
File No. 1-8038).
4.14 Warrant Registration Rights Agreement dated January 22,
1999, by and among the Company and Lehman Brothers Inc.,
Bear, Stearns & Co. Inc., F.A.C./Equities, a division of
First Albany Corporation, and Dain Rauscher Wessels, a
division of Dain Rauscher Incorporated. (Incorporated by
reference to Exhibit 99(e) of the Company's Form 8-K filed
on February 3, 1999, File No. 1-8038).

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 Amended and Restated Credit Agreement among Key Energy
Group, Inc. and several other financial institutions dated
as of June 6, 1997 as amended and restated through
November 6, 1997. (Incorporated by reference to Exhibit
10(s) of the Company's Quarterly Report on Form 10-Q for
the quarter ended December 31, 1997, File No. 1-8038).
10.3 First Amendment to the Amended and Restated Credit Agreement
dated as of June 6, 1997, as amended and restated through
November 6, 1997 dated December 3, 1997. (Incorporated by
reference to Exhibit 10(t) of the Company's Quarterly
Report on Form 10-Q for the quarter ended December 31,
1997, File No. 1-8038).
10.4 Asset Purchase Agreement between Brooks Well
Servicing, Inc. and Sam F. McKee, Individually and d/b/a
Circle M Vacuum Services, effective as of January 30,
1998. (Incorporated by reference to Exhibit 10(m) of the
Company's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1997, File No. 1-8038).
10.5 Stock Purchase Agreement between Key Energy Drilling, Inc.
and Jack B. Loveless, Jim Mayfield and J.W. Miller,
effective as of January 30, 1998. (Incorporated by
reference to Exhibit 10(n) of the Company's Quarterly
Report on Form 10-Q for the quarter ended December 31,
1997, File No. 1-8038).
10.6 Asset Purchase Agreement between Key Four Corners, Inc. and
Four Corners Drilling, R.L. Andes and W.E. Lang, effective
as of January 30, 1998. (Incorporated by reference to
Exhibit 10(o) of the Company's Quarterly Report on Form
10-Q for the quarter ended December 31, 1997, File No.
1-8038).
10.7 Asset Purchase Agreement among Key Rocky Mountain, Inc.,
Updike Brothers, Inc. Employee Stock Ownership Retirement
Plan and Trust, David W. Updike Trust, Dorothy A. Updike
Trust, Dorothy R. Updike Trust, Mary E. Updike, Ralph O.
Updike and Daniel Updike effective February 6, 1998.
(Incorporated by reference to Exhibit 10(p) of the
Company's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1997, File No. 1-8038).
10.8 Asset Purchase Agreement among Brooks Well Servicing, Inc.,
Hot Oil Plus, Inc., Thomas N. Novosad, Jr. and Patricia
Novosad effective January 29, 1998. (Incorporated by
reference to Exhibit 10(q) of the Company's Quarterly
Report on Form 10-Q for the quarter ended December 31,
1997, File No. 1-8038).
10.9 Asset Purchase Agreement among Brooks Well Servicing, Inc.,
Lundy Vacuum Service, Inc. and Peyton E. Lundy effective
March 3, 1998. (Incorporated by reference to Exhibit
10(a) of the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 1998, File No. 1-8038).
10.10 Asset Purchase Agreement among Yale E. Key, Inc., Edwards
Transport, Inc. and Tom Nations effective March 26, 1998.
(Incorporated by reference to Exhibit 10(b) of the
Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998, File No. 1-8038).
10.11 Asset Purchase Agreement among Brooks Well Servicing, Inc.
and JPF Well Service Inc., effective April 20, 1998.
(Incorporated by reference to Exhibit 10(c) of the
Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998, File No. 1-8038).
10.12 Asset Purchase Agreement among Brooks Well Servicing, Inc.
and JPF Lease Service Inc., effective April 20, 1998.
(Incorporated by reference to Exhibit 10(d) of the
Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998, File No. 1-8038).
10.13 Asset Purchase Agreement between Watson Oilfield Service &
Supply, Inc. and Watson Truck & Supply, Inc. dated
May 19, 1998. (Incorporated by reference to Exhibit 10.68
of the Company's Annual Report Form 10-K for the year
ended June 30, 1998, File No. 1-8038).

10.14 Purchase and Sale Agreement among Burnett Corporation, B.O.
Cornelius, Ann C. Fatheree, James R. Corbin, Mary Jo
Mitton, Birke B. Marsh, H. Cobb, Birke B. Marsh, Trustee
of the Corbin Trust, Jamie Kim Corbin, Josh Alan Corbin,
Jason J. Corbin, Wilbanks Exploration, Inc. and Odessa
Exploration, Inc. dated May 20, 1998. (Incorporated by
reference to Exhibit 10.69 of the Company's Annual Report
Form 10-K for the year ended June 30, 1998, File No.
1-8038).
10.15 Asset Purchase Agreement among Key Energy Drilling, Inc.,
Lakota Drilling Company and Reed Gilmore, Priscilla
Gilmore, M. Reed Gilmore, Jr., Valerie G. Griess, Joan G.
Lindquist, James C. Gilmore, L. E. Grimes and Larry V.
Bohannon dated May 22, 1998. (Incorporated by reference to
Exhibit 10.70 of the Company's Annual Report Form 10-K for
the year ended June 30, 1998, File No. 1-8038).
10.16 Key Energy Group, Inc. 1997 Incentive Plan (Incorporated by
reference to Exhibit B of the Company's definitive proxy
statement dated November 28, 1997, File No. 1-8038).
10.17 Asset Purchase Agreement among Key Four Corners, Inc.,
Colorado Well Service, Inc. and Keith Poole dated as of
July 10, 1998. (Incorporated by reference to Exhibit
10(a) of the Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1998, File No. 1-8038).
10.18 Asset Purchase Agreement among Key Energy Services - South
Texas, Inc. and TransTexas Gas Corporation dated as of
August 17, 1998. (Incorporated by reference to
Exhibit 10(b) of the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1998, File No.
1-8038).
10.19 Asset Purchase Agreement among Key Energy Group, Inc., Flint
Engineering & Construction Co. and Flint Industries, Inc.
dated as of September 9, 1998. (Incorporated by reference
of Exhibit 10(c) of the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1998, File No.
1-8038).
10.20 Asset Purchase Agreement among Dawson Production Partners,
L.P., Dawson Production Services, Inc., and Hellums
Services II, Inc., Superior Completion Services, Inc.,
South Texas Disposal, Inc., Elsik II, Inc., Roger D.
Hellums, Charles C. Forbes, Jr., Robert W. Randle, Jr.,
Ronald D. Brieden, John E. Crisp, Charles Talley, and
James J. Acker dated as of August 14, 1998. (Incorporated
by reference to Exhibit 10(d) of the Company's Quarterly
Report on Form 10-Q for the quarter ended September 30,
1998, File No. 1-8038).
10.21 Commitment Letter between Key Energy Group, Inc. and PNC
Bank, N.A., dated as of August 17, 1998 (Incorporated by
reference to Exhibit (b)(1) of Schedule 14D-1 and Schedule
13D filed by Midland Acquisition Corp. and the Company on
August 12, 1998, File No. 5-47031).
10.22 Engagement Letter between Key Energy Group, Inc. and Bear,
Stearns & Co, Inc., dated as of May 8, 1998. (Incorporated
by reference to Exhibit (b)(2) of Schedule 14D-1 and
Schedule 13D filed by Midland Acquisition Corp. and the
Company on August 12, 1998, File No. 5-47031).
10.23 Engagement Letter between Key Energy Group, Inc. and Dain
Rauscher Wessels, dated as of July 2, 1998. (Incorporated
by reference to Exhibit (b)(3) of Schedule 14D-1 and
Schedule 13D filed by Midland Acquisition Corp. and the
Company on August 12, 1998, File No. 5-47031).
10.24 Confidentiality Agreement, dated as of August 8, 1998 by and
among Key Energy Group, Inc., Midland Acquisition Corp.
and Dawson Production Services, Inc. (Incorporated by
reference to Exhibit (c)(2) of Schedule 14D-1 and Schedule
13D filed by Midland Acquisition Corp. and the Company on
August 12, 1998, File No. 5-47031).
10.25 Agreement and Plan of Merger, dated as of August 11, 1998,
by and among Key Energy Group, Inc., Midland Acquisition
Corp. and Dawson Production Services, Inc. (Incorporated
by reference to Exhibit 2.1 of the Company's Current
Report on Form 8-K dated September 28, 1998, File No.
1-8038).

10.26 $150,000,000 Bridge Loan Agreement, dated as of
September 14, 1998 among Key Energy Group, Inc., Lehman
Brothers Inc., Lehman Commercial Paper Inc., and certain
lenders and guarantors (Incorporated by reference to
Exhibit 99.1 of the Company's Current Report on Form 8-K
dated September 28, 1998, File No. 1-8038).
10.27 Escrow Agreement among Key Energy Group, Inc., Lehman
Brothers Inc., Lehman Commercial Paper Inc. and The Bank
of New York, dated as of September 14, 1998 (Incorporated
by reference to Exhibit 99.6 of the Company's Current
Report on Form 8-K dated September 28, 1998, File No.
1-8038).
10.28 $550,000,000 Second Amended and Restated Credit Agreement,
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).
10.29 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).
10.30 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).
10.31 Form of Indemnification Agreement and provisions regarding
indemnification of directors and officers from the
Company's Articles of Incorporation and Bylaws
(Incorporated by reference to Exhibit 3 of the Schedule
14D-9 filed by Dawson Production Services, Inc. on
August 17, 1998, File No. 5-47031).
10.32 Employment Agreement dated as of April 1, 1996 between
Dawson Production Services, Inc. and Michael E. Little
(Incorporated by reference to Exhibit 4 of the Schedule
14D-9 filed by Dawson Production Services, Inc. on
August 17, 1998, File No. 5-47031).
10.33 Amendment No. 1 to Employment Agreement between Dawson
Production Services, Inc. and Michael E. Little
(Incorporated by reference to Exhibit 5 of the Schedule
14D-9 filed by Dawson Production Services, Inc. on
August 17, 1998, File No. 5-47031).
10.34 Amendment No. 2 to Employment Agreement between Dawson
Production Services, Inc. and Michael E. Little
(Incorporated by reference to Exhibit 6 of the Schedule
14D-9 filed by Dawson Production Services, Inc. on
August 17, 1998, File No. 5-47031).
10.35 Employment Agreement dated as of April 1, 1996 between
Dawson Production Services, Inc. and Joseph Eustace
(Incorporated by reference to Exhibit 7 of the Schedule
14D-9 filed by Dawson Production Services, Inc. on
August 17, 1998, File No. 5-47031).
10.36 Amendment No. 1 to Employment Agreement between Dawson
Production Services, Inc. and Joseph Eustace (Incorporated
by reference to Exhibit 8 of the Schedule 14D-9 filed by
Dawson Production Services, Inc. on August 17, 1998, File
No. 5-47031).
10.37 Employment Agreement dated as of July 1, 1998 between Dawson
Production Services, Inc. and Jim Byerlotzer (Incorporated
by reference to Exhibit 9 of the Schedule 14D-9 filed by
Dawson Production Services, Inc. on August 17, 1998, File
No. 5-47031).
10.38 Amendment No. 1 to Employment Agreement between Dawson
Production Services, Inc. and Jim Byerlotzer (Incorporated
by reference to Exhibit 10 of the Schedule 14D-9 filed by
Dawson Production Services, Inc. on August 17, 1998, File
No. 5-47031).
10.39 Employment Agreement dated as of April 1, 1996 between
Dawson Production Services, Inc. and P. Mark Stark
(Incorporated by reference to Exhibit 11 of the Schedule
14D-9 filed by Dawson Production Services, Inc. on
August 17, 1998, File No. 5-47031).

10.40 Amendment No. 1 to Employment Agreement between Dawson
Production Services, Inc. and P. Mark Stark (Incorporated
by reference to Exhibit 12 of the Schedule 14D-9 filed by
Dawson Production Services, Inc. on August 17, 1998, File
No. 5-47031).
10.41 Employee Severance Pay Plan of Dawson Production
Services, Inc. (Incorporated by reference to Exhibit 13 of
the Schedule 14D-9 filed by Dawson Production
Services, Inc. on August 17, 1998, File No. 5-47031).
10.42 Consulting Agreement Term Sheet dated August 11, 1998
between the Company and Midland Acquisition Corp. and
Michael E. Little (Incorporated by reference to Exhibit 14
of the Schedule 14D-9 filed by Dawson Production
Services, Inc. on August 17, 1998, File No. 5-40731).
10.43 Consulting Agreement Term Sheet dated August 11, 1998
between the Company and Midland Acquisition Corp. and
James J. Byerlotzer (Incorporated by reference to Exhibit
15 of the Schedule 14D-9 filed by Dawson Production
Services, Inc. on August 17, 1998, File No. 5-47031).
10.44 Consulting Agreement Term Sheet dated August 11, 1998
between the Company and Midland Acquisition Corp. and
Joseph E. Eustace (Incorporated by reference to Exhibit 16
of the Schedule 14D-9 filed by Dawson Production
Services, Inc. on August 17, 1998, File No. 5-47031).
10.45 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).
10.46 Employment Agreement, dated November 13, 1998, by and
between Key Energy Group, Inc. and James J. Byerlotzer.
(Incorporated by reference to Exhibit 10(b) the Company's
Quarterly Report on Form 10-Q for the quarter ended
December 31, 1998, File No. 1-8038).
10.47 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).
10.48 Employment Agreement, dated October 20, 1998, by and between
Key Energy Group, Inc. and Joseph B. Eustace.
(Incorporated by reference to Exhibit 10(d) of the
Company's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1998, File No. 1-8038).
10.49 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).
10.50 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).
10.51 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).
10.52 First Amendment, dated as of December 3, 1997, to the Second
Amended and Restated Credit Agreement, 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).
10.53 Second Amendment, dated as of December 29, 1998, to the
Second Amended and Restated Credit Agreement, 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).

10.54 Stock Purchase Agreement among 3022481 Nova Scotia Company
and Donald Bowling, Howard Bowling, Ronald Bowling,
Corunna Petroleum Limited effective October 22, 1998.
(Incorporated by reference to Exhibit 10(j) of the
Company's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1998, File No. 1-8038).
10.55 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).
10.56 Employment Agreement between the Company and William C.
McCurdy dated as of January 4, 1999. (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).
10.57 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).
10.58 Purchase Agreement, among the Company, Green-Cohn Group,
LLC, ZPG Securities L.L.C. and DFG Corporation, dated as
of April 15, 1999. (Incorporated by reference to
Exhibit 99.2 of the Company's Current Report on Form 8-K
dated April 8, 1999, File No. 1-8038).
10.59 Commitment Letter, between the Company and PNC Investment
Corp., dated April 15, 1999. (Incorporated by reference to
Exhibit 99.3 of the Company's Current Report on Form 8-K
dated April 8, 1999, File No. 1-8038).
10.60 Fee letter, between the Company and PNC Capital
Markets, Inc., dated April 15, 1999. (Incorporated by
reference to Exhibit 99.4 of the Company's Current Report
on Form 8-K dated April 8, 1999, File No. 1-8038).
10.61 Third Amendment, dated as of April 8, 1999, to the Second
Amended and Restated Credit Agreement, 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).
10.62 Fourth Amendment, dated as of April 15, 1999, to the Second
Amended and Restated Credit Agreement, 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).
10.63 Underwriting Agreement, dated May 4, 1999, among the
Company, and Friedman, Billings, Ramsey & Co., Inc., for
itself and as representative for the other underwriter
named in Schedule I thereto. (Incorporated by reference to
Exhibit 1.1 of the Company's Current Report on Form 8-K
dated May 4, 1999, File No. 1-8038).
10.64 Letter Agreement, dated May 4, 1999, among the Company, PNC
Capital Markets, Inc. and PNC Investment Corp.
(Incorporated by reference to Exhibit 99.1 of the
Company's Current Report on Form 8-K dated May 4, 1999,
File No 1-8038).
10.65 Fifth Amendment, dated as of May 10, 1999, to the Second
Amended and Restated Credit Agreement, among the Company,
the several lenders from time to time parties thereto, PNC
Bank, National Association, as Administrative Agent,
Norwest Bank Texas, N.A., as Collateral Agent, and PNC
Capital Markets, Inc., as Arranger. (Incorporated by
reference to Exhibit 10.91 of the Company's Annual Report
on Form 10-K dated June 30, 1999, File No. 1-8038).
10.66 Consulting Agreement between Key Energy Group, Inc. and The
Old Hill Company LLC dated as of December 2, 1998.
(Incorporated by reference to Exhibit 10.92 of the
Company's Annual Report on Form 10-K dated June 30, 1999,
File No. 1-8038).
10.67 Amended and Restated Employment Agreement dated July 1,
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 September 30, 1999, File No. 1-8038).

10.68 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).
10.69 Employment Agreement dated July 1, 1999, between Danny R.
Evatt and Key Energy Services, Inc. (Incorporated by
reference to Exhibit 10.3 of the Company's Quarterly
Report on Form 10-Q for the quarter ended September 30,
1999, File No. 1-8038).
10.70 Employment Agreement dated July 1, 1999, between James J.
Byerlotzer and Key Energy Services, Inc. (Incorporated by
reference to Exhibit 10.4 of the Company's Quarterly
Report on Form 10-Q for the quarter ended September 30,
1999, File No. 1-8038).
10.71 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).
10.72 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).
10.73 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).
10.74 Confidential Separation and Release Agreement dated as of
July 1, 1999, between Key Energy Services, Inc. and
Stephen E. McGregor (Incorporated by reference to Exhibit
10.8 of the Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1999, File No. 1-8038).
10.75 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).
10.76 Amendment No. 1 dated as of November 24, 1999, to the
Confidential Separation and Release Agreement dated as of
July 1, 1999, between Key Energy Services, Inc. and
Stephen E. McGregor (Incorporated by reference to Exhibit
10.2 of the Company's Quarterly Report on Form 10-Q for
the quarter ended December 31, 1999, File No. 1-8038).
10.77 Sixth Amendment, dated as of July 14, 1999, to the Second
Amended and Restated Credit Agreement, 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).
10.78 Seventh Amendment, dated as of March 1, 2000, to the Second
Amended and Restated Credit Agreement, 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).
10.79 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).
10.80 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).

10.81 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).
*10.82 Membership Interest Exchange Agreement dated April 5, 2000
by and between Tetra Services, Inc. and Brooks Well
Servicing, Inc.
*10.83 Amendment No. 2 dated as of June 16, 2000 to Agreement dated
as of August 2, 1999, as amended between Francis D. John
and Key Energy Services, Inc.
*21 Significant Subsidiaries of the Company.
*23 Consent of KPMG LLP.
*27 Financial Data Schedule.

(b) Reports on Form 8-K

The Company filed the following reports on Form 8-K during the quarter ended
June 30, 2000:

(i) Current Report on Form 8-K dated June 14, 1999 filed to report the
addition of a seventh member to the Board of Directors.

(ii) Current Report on Form 8-K dated June 19, 1999 filed to report, among
other things, the undertaking of certain strategic projects and the
commencement of an underwritten public offering of its common stock via
an effective shelf registration statement.

(iii) Current Report on Form 8-K dated June 29, 1999, as amended June 30,
2000 filed to report, among other things, that the Company had entered
into an underwriting agreement in connection with the offering referred
to in clause (ii) above.

- ------------------------

* Filed herewith.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, this Registration has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

KEY ENERGY SERVICES, INC.
(Registrant)

Dated: September 28, 2000 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 28, 2000 By: /s/ FRANCIS D. JOHN
---------------------------------------------
Francis D. John
CHAIRMAN OF THE BOARD, PRESIDENT,
AND CHIEF EXECUTIVE OFFICER

Dated: September 28, 2000 By: /s/ THOMAS K. GRUNDMAN
---------------------------------------------
Thomas K. Grundman
CHIEF FINANCIAL OFFICER
AND CHIEF ACCOUNTING OFFICER

Dated: September 28, 2000 By: /s/ MORTON WOLKOWITZ
---------------------------------------------
Morton Wolkowitz
DIRECTOR

Dated: September 28, 2000 By: /s/ DAVID J. BREAZZANO
---------------------------------------------
David J. Breazzano
DIRECTOR

Dated: September 28, 2000 By: /s/ WILLIAM MANLY
---------------------------------------------
William Manly
DIRECTOR

Dated: September 28, 2000 By: /s/ KEVIN P. COLLINS
---------------------------------------------
Kevin P. Collins
DIRECTOR

Dated: September 28, 2000 By: /s/ W. PHILLIP MARCUM
---------------------------------------------
W. Phillip Marcum
DIRECTOR

Dated: September 28, 2000 By: /s/ WILLIAM D. FERTIG
---------------------------------------------
William D. Fertig
DIRECTOR

SCHEDULE II

KEY ENERGY SERVICES, INC.

CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

AS OF JUNE 30,

(IN THOUSANDS)

ADDITIONS
BALANCE AT ------------------------------
BEGINNING OF CHARGED TO CHARGED TO BALANCE AT
YEAR EXPENSES OTHER ACCOUNTS(A) DEDUCTIONS END OF YEAR
------------ ---------- ----------------- ---------- -----------

Allowance for doubtful accounts:
2000................................. $6,790 $1,648 $ 0 $5,249 $3,189
1999................................. 2,843 5,928 3,112 5,093 6,790
1998................................. 1,552 826 1,161 696 2,843

- ------------------------

(a) Additions to allowance for doubtful accounts established through purchase
accounting.

S-1