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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K/A
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED JUNE 30, 2002
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-8038
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KEY ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)
MARYLAND 04-2648081
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6 DESTA DRIVE, MIDLAND, TEXAS 79705
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (915) 620-0300
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
----------------------------- -----------------------------------------
Common Stock, $.10 par value New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
5% Convertible Subordinated Notes Due 2004
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Exchange Act during the past
12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/
The aggregate market value of the Common Shares held by nonaffiliates of the
Registrant as of October 25, 2002 was approximately $1,055,836,708.
Common Shares outstanding at October 25, 2002: 128,109,917
DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Proxy Statement with
respect to the Annual Meeting of Shareholders for the fiscal year ended
June 30, 2002 are incorporated by reference in Part III of this report.
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KEY ENERGY SERVICES, INC.
INDEX
PART I.
Item 1. Business.................................................... 3
Item 2. Properties.................................................. 11
Item 3. Legal Proceedings and Other Actions......................... 11
Item 4. Submission of Matters to a Vote of Security Holders......... 11
PART II.
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters......................................... 12
Item 6. Selected Financial Data..................................... 14
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition.......................... 15
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 22
Item 8. Consolidated Financial Statements and Supplementary Data.... 25
Item 9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure.................................... 64
PART III.
Item 10. Directors and Executive Officers............................ 64
Item 11. Executive Compensation...................................... 66
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 71
Item 13. Certain Relationships and Related Transactions.............. 72
Item 14. Disclosure Controls and Procedures.......................... 73
PART IV.
Item 15. Exhibits, Financial Statements and Reports on Form 8-K...... 73
2
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
The statements in this document that relate to matters that are not
historical facts are "forward-looking statements" within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. When used in this document and the documents incorporated by reference,
words such as "anticipate," "believe," "expect," "plan," "intend," "estimate,"
"project," "will," "could," "may," "predict" and similar expressions are
intended to identify forward-looking statements. Further events and actual
results may differ materially from the results set forth in or implied in the
forward-looking statements. Factors that might cause such a difference include:
- fluctuations in world-wide prices and demand for oil and natural gas;
- fluctuations in level of oil and natural gas exploration and development
activities;
- fluctuations in the demand for well servicing, contract drilling and
ancillary oilfield services;
- the existence of competitors, technological changes and developments in
the industry;
- the existence of operating risks inherent in the well servicing, contract
drilling and ancillary oilfield services; and
- general economic conditions, the existence of regulatory uncertainties,
and the possibility of political instability in any of the countries in
which Key does business, in addition to other matters discussed under
"Part II--Item 7--Management's Discussion and Analysis of Results of
Operations and Financial Condition."
PART I
ITEM 1. BUSINESS.
THE COMPANY
Key Energy Services, Inc. (the "Company" or "Key"), is the largest onshore,
rig-based well servicing contractor in the world, with approximately 1,486 well
service rigs and 1,719 oilfield service vehicles as of June 30, 2002. Key
provides a complete range of well services to major oil companies and
independent oil and natural gas production companies, including: rig-based well
maintenance, workover, completion, and recompletion services (including
horizontal recompletions); oilfield trucking services; and ancillary oilfield
services. Key conducts well servicing operations onshore the continental United
States in the following regions: Gulf Coast (including South Texas, Central Gulf
Coast of Texas and South Louisiana), Permian Basin of West Texas and Eastern New
Mexico, Mid-Continent (including the Anadarko, Hugoton and Arkoma Basins and the
ArkLaTex region), Four Corners (including the San Juan, Piceance, Uinta, and
Paradox Basins), Eastern (including the Appalachian, Michigan and Illinois
Basins), Rocky Mountains (including the Denver-Julesberg, Powder River, Wind
River, Green River and Williston Basins), and California (the San Joaquin
Basin), and internationally in Argentina, Egypt and Ontario, Canada. Key is also
a leading onshore drilling contractor, with 79 land drilling rigs as of
June 30, 2002. Key conducts land drilling operations in a number of major
domestic producing basins, as well as in Argentina and in Ontario, Canada. Key
also produces and develops oil and natural gas reserves in the Permian Basin
region and Texas Panhandle.
Key's principal executive office is located at 6 Desta Drive, Midland, Texas
79705. Key's phone number is (915) 620-0300 and website address is
www.keyenergy.com.
BUSINESS STRATEGY
Key has built its leadership position through the consolidation of smaller,
less viable competitors. This 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
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strengthen its position within the industry during fiscal 2001 and 2002. Key has
focused on maximizing results by reducing debt, building strong customer
alliances, refurbishing rigs and related equipment, and training personnel to
maintain a qualified and safe employee base.
REDUCING DEBT. Over the past fiscal year, Key has significantly reduced
debt and strengthened its balance sheet. At June 30, 2002, Key's long-term
funded debt net of cash and capitalized leases ("net funded debt") was
approximately $366,634,000 and its net funded debt to capitalization ratio was
approximately 41% as compared to approximately $468,845,000 and 50%,
respectively, at June 30, 2001. Key expects to be able to continue to reduce
debt from available cash flow from operations and from anticipated interest
savings resulting from prior and future debt reductions and future debt
refinancings.
BUILDING STRONG CUSTOMER ALLIANCES. Key seeks to maximize customer
satisfaction by offering a broad range of equipment and services combined with a
highly trained and motivated labor force. As a result, Key is able to offer
proactive solutions for most of its customer's wellsite needs. Key ensures
consistent high standards of quality and customer satisfaction by continually
evaluating its performance. Key maintains strong alliances with major oil
companies as well as numerous independent oil and natural gas production
companies and believes that such alliances improve the stability of demand for
its oilfield services.
REFURBISHING RIGS AND RELATED EQUIPMENT. Key intends to continue actively
refurbishing its rigs and related equipment to maximize the utilization of its
rig fleet. The increase in Key's cash flow, both from operations and from
anticipated interest savings from reduced levels of debt, combined with Key's
borrowing availability under its revolving credit facility, has provided ample
liquidity and resources necessary to make the capital expenditures to refurbish
such equipment.
TRAINING AND DEVELOPING EMPLOYEES. Key has, and will continue to, devote
significant resources to the training and professional development of its
employees with a special emphasis on safety. Key currently has two training
centers in Texas and one training center in California to improve its employees'
understanding of operating and safety procedures. Key recognizes the
historically high turn-over rate in the industry and is committed to offering
compensation, benefits and incentive programs for its employees that are
attractive and competitive in its industry, in order to ensure a steady stream
of qualified, safe personnel to provide quality service to its customers.
MAJOR DEVELOPMENTS DURING AND SUBSEQUENT TO FISCAL 2002
DEPRESSED INDUSTRY CONDITIONS
Operating conditions declined significantly during fiscal 2002 as capital
spending by oil and natural gas producers for well servicing and contract
drilling services decreased from prior year levels. The decreased spending was
primarily due to lower commodity prices (and the perception by the Company's
customers that commodity prices will decrease further) with WTI Cushing prices
for light sweet crude averaging approximately $23.81 per barrel and Nymex Henry
Hub natural gas prices averaging approximately $2.77 per MMbtu during fiscal
2002, as compared to an average WTI Cushing price for light sweet crude of
$26.97 per barrel and an average Nymex Henry Hub natural gas price of $5.09 per
MMbtu during fiscal 2001.
The lower commodity prices during fiscal 2002 led to a rapid decrease in the
demand for Key's services and equipment beginning in the December 2001 quarter
as Key's customers reduced their exploration and development activity in Key's
primary market areas. Beginning in late calendar 2001, rising natural gas
inventories and the prospect of a slowing economy caused concern in the
commodity markets which resulted in a steady decline in commodity prices. The
lower commodity prices, along with the change in market sentiment, forced some
of our customers to reduce/delay their capital spending plans. Despite the
decline in activity, Key was successful in minimizing rate concessions; however,
the decrease in demand and moderately lower rates resulted in sequential
decreases in revenues, cash flow and net income in the
4
last three quarters of fiscal 2002 over the same quarters of fiscal 2001. Key
expects demand for its services to gradually improve from its existing levels as
commodity prices have improved with WTI Cushing prices averaging $28.35 per
barrel and Nymex Henry Hub natural gas prices averaging $3.05 per MMbtu during
the month of August 2002.
Despite the decline from fiscal 2001, crude oil prices continued to trade at
healthy levels during fiscal 2002 due largely to the ability of the Organization
of Petroleum Exporting Countries ("OPEC") to adhere to its production quotas
designed to keep crude oil prices in the range of $22.00 to $28.00 per barrel.
The adherence to the production quotas brought more stability to crude oil
prices; however, between November 2001 and February 2002, crude oil prices did
decline and averaged less than $20 per barrel. The decline in pricing led many
oil and gas producers to reduce their capital spending until such time that
commodity prices recovered. Since February 2002, crude oil prices have
strengthened due to concerns of a potential Middle East conflict, lower oil
inventories and the prospects of an improving economy. During this same period,
natural gas prices have also improved. Since February 2002, Nymex Henry Hub
prices have improved to $3.05 per MMbtu from $2.23 per MMbtu. Despite today's
strong commodity prices, activity continues to remain modest, although the
Company has experienced slight improvements in rig hours during the past few
months. While management believes that many of its customers generally base
their capital spending budgets on a crude oil price of $18.00 to $22.00 per
barrel and a natural gas price of $2.00 to $2.75 per MMbtu, there can be no
assurances that its customers will not postpone and/or reduce their capital
spending plans if crude oil prices and natural gas prices continue to remain at
or below their current levels. Assuming no further weakening in the U.S. economy
and a normal winter in the United States, management believes that activity
levels should improve during calendar 2003.
The level of Key's revenues, cash flows, losses and earnings are
substantially dependent upon, and affected by, the level of domestic and
international oil and gas exploration and development activity (See Part
II--Item 7--Management's Discussion and Analysis of Results of Operations and
Financial Condition).
DEBT REDUCTION
During fiscal 2002, Key significantly reduced its long-term debt and
strengthened its balance sheet. At June 30, 2002, Key's net funded debt was
approximately $366,634,000 and its net funded debt to capitalization ratio was
approximately 41% as compared to approximately $468,845,000 and 50%,
respectively, at June 30, 2001. Proceeds from the Equity Offering (defined
below) and the Debt Offering (defined below), as well as cash flow from
operations were used to accomplish this reduction in net funded debt (see
Part II--Item 7--Management's Discussion and Analysis of Results of Operations
and Financial Condition--Long-Term Debt).
EQUITY OFFERING
On December 19, 2001, the Company closed a public offering of 5,400,000
shares of common stock, yielding approximately $43.2 million, or $8.00 per
share, to the Company, (the "Equity Offering"). Net proceeds from the Equity
Offering of approximately $42.6 million were used to temporarily reduce amounts
outstanding under the Company's revolving line of credit. The net proceeds of
the Equity Offering were ultimately used in January 2002 to redeem a portion of
the Company's 14% Senior Subordinated Notes fully utilizing the Company's equity
"claw-back" rights for up to 35% of the original $150 million issued.
DEBT OFFERING
On March 1, 2002, Key completed a public offering of $100,000,000 of 8 3/8%
Senior Notes Due 2008 at 101.5% of par (the "Debt Offering"). The cash proceeds
from the public offering, net of fees and expenses, were used to repay the
entire balance of the revolving loan facility then outstanding under Key's
senior
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credit facility, with the remainder of such proceeds held in cash and ultimately
used to retire a portion of Q Services, Inc.'s long-term debt.
EGYPT PROJECT
On March 28, 2002, Key entered into a multi-year contract with Apache
Corporation under which Key is providing five newly refurbished well servicing
rigs for work on Apache concessions in the Western Desert of the Arab Republic
of Egypt. In addition to the five well servicing rigs, Key is also providing
Apache with ten heavy oilfield service vehicles under the contract.
ACQUISITIONS
During fiscal 2002, the Company completed a series of small acquisitions for
total consideration of $44,378,000, which consisted of a combination of cash and
shares of the Company's common stock. None of the acquisitions completed in
fiscal 2002 were individually material, thus the pro forma effect of these
acquisitions is not required to be presented. Each of the acquisitions was
accounted for using the purchase method and the results of the operations
generated from the acquired assets are included in the Company's results of
operations as of the completion date of each acquisition.
ACQUISITION OF Q SERVICES, INC.
On July 19, 2002, Key acquired Q Services, Inc. ("QSI") pursuant to an
Agreement and Plan of Merger dated May 13, 2002, as amended, by and among Key,
Key Merger Sub, Inc. and QSI. As consideration for the merger, the Company
issued approximately 17.2 million shares of its common stock to QSI shareholders
and assumed approximately $74 million of QSI's indebtedness, net of working
capital. The aggregate value of the consideration, including assumed debt, was
approximately $221 million. Prior to the acquisition, QSI was a privately held
corporation conducting field production, pressure pumping and other service
operations in Louisiana, New Mexico, Oklahoma, Texas and the Gulf of Mexico.
NEW SENIOR CREDIT FACILITY
On July 15, 2002, the Company entered into a Third Amended and Restated
Credit Agreement (the "New Senior Credit Facility"). The New Senior Credit
Facility consists of a $150,000,000 revolving loan facility with a $40,000,000
sublimit for letters of credit. The loans are secured by most of the tangible
and intangible assets of the Company. The revolving loan commitment will
terminate on July 15, 2005 and all revolving loans must be paid on or before
that date. The revolving loans bear interest based upon, at the Company's
option, the prime rate plus a variable margin of 0.00% to 0.75% or a Eurodollar
rate plus a variable margin of 1.25% to 2.75%. The New Senior Credit Facility
has customary affirmative and negative covenants including a maximum leverage
ratio, a minimum fixed charge coverage ratio and a minimum net worth, as well as
limitations on liens and indebtedness and restrictions on dividends,
acquisitions and dispositions.
DESCRIPTION OF BUSINESS SEGMENTS
Key operates in two primary business segments which are well servicing and
contract drilling. Key's operations are conducted domestically and in Argentina,
Egypt and Canada. The following is a description of each of these business
segments (for financial information regarding these business segments, see
Note 13 to Consolidated Financial Statements--Business Segment Information).
WELL SERVICING
Key provides a full range of well services, including rig-based services,
oilfield trucking services, fishing and rental tool services, pressure pumping
services and other ancillary oilfield services, necessary to maintain and
workover oil and natural gas producing wells. Rig-based services include:
maintenance of
6
existing wells, workovers of existing wells, completion of newly drilled wells,
recompletion of existing wells (including horizontal recompletions) and plugging
and abandonment of wells at the end of their useful lives.
WELL SERVICE RIGS
Key uses its well service rig fleet to perform four major categories of rig
services for oil and natural gas producers.
MAINTENANCE SERVICES. Key estimates that there are approximately 600,000
producing oil wells and approximately 300,000 producing natural gas wells in the
United States. Key provides the well service rigs, equipment and crews for
maintenance services, which are performed on both oil and natural gas wells, but
which are more commonly required on oil wells. While some oil wells in the
United States flow oil to the surface without mechanical assistance, most
require pumping or some other method of artificial lift. Oil wells that require
pumping characteristically require more maintenance than flowing wells due to
the operation of the mechanical pumping equipment installed. Few natural gas
wells have mechanical pumping systems in the wellbore, and, as a result,
maintenance work on natural gas wells is less frequent.
Maintenance services are required throughout the life of most producing oil
and natural gas wells to ensure efficient and continuous operation. These
services consist of routine mechanical repairs necessary to maintain production
from the well, such as repairing inoperable pumping equipment in an oil well or
replacing defective tubing in an oil or natural gas well, and removing debris
such as sand and paraffin from the well. Other services include pulling the
rods, tubing, pumps and other downhole equipment out of the wellbore to identify
and repair a production problem.
Maintenance services are often performed on a series of wells in proximity
to each other and typically require less than 48 hours per well to complete. The
general demand for maintenance services is closely related to the total number
of producing oil and natural gas wells in a geographic market, and maintenance
services are generally the most stable type of well service activity.
WORKOVER SERVICES. In addition to periodic maintenance, producing oil and
natural gas wells occasionally require major repairs or modifications, called
"workovers." Workover services are performed to enhance the current production
of existing wells. Such services include extensions of existing wells to drain
new formations either through deepening wellbores to new zones or through
drilling of horizontal lateral wellbores to improve reservoir drainage patterns.
In less extensive workovers, Key's rigs are used to seal off depleted zones in
existing wellbores and access previously bypassed productive zones. Key's
workover rigs are also used to convert former producing wells to injection wells
through which water or carbon dioxide is then pumped into the formation for
enhanced recovery operations. Other workover services include: major subsurface
repairs such as casing repair or replacement, recovery of tubing and removal of
foreign objects in the wellbore, repairing downhole equipment failures, plugging
back the bottom of a well to reduce the amount of water being produced with the
oil and natural gas, cleaning out and recompleting a well if production has
declined, and repairing leaks in the tubing and casing. These extensive workover
operations are normally performed by a well service rig with a workover package,
which may include rotary drilling equipment, mud pumps, mud tanks and blowout
preventers depending upon the particular type of workover operation. Most of
Key's well service rigs are designed for and can be equipped to perform complex
workover operations.
Workover services are more complex and time consuming than routine
maintenance operations and consequently may last from a few days to several
weeks. These services are almost exclusively performed by well service rigs.
The demand for workover services is more sensitive to expectations relating
to, and changes in, oil and natural gas prices than the demand for maintenance
services. As oil and natural gas prices increase, the
7
level of workover activity tends to increase as operators seek to increase
production by enhancing the efficiency of their wells at higher commodity prices
with correspondingly higher rates of return.
COMPLETION SERVICES. Key's completion services prepare a newly drilled oil
or natural gas well for production. The completion process may involve
selectively perforating the well casing to access producing zones, stimulating
and testing these zones and installing downhole equipment. Key typically
provides a well service rig and may also provide other equipment such as a
workover package to assist in the completion process. Producers use well service
rigs to complete their wells because the rigs have specialized equipment,
properly trained employees and the experience necessary to perform these
services. However, during periods of weak drilling rig demand, drilling
contractors may compete with service rigs for completion work.
The completion process typically requires a few days to several weeks,
depending on the nature and type of the completion, and generally requires
additional auxiliary equipment that can be provided for an additional fee. The
demand for well completion services is directly related to drilling activity
levels, which are highly sensitive to expectations relating to, and changes in,
oil and natural gas prices. As the number of newly drilled wells decreases, the
number of completion jobs correspondingly decreases.
PLUGGING AND ABANDONMENT SERVICES. Well service rigs and workover equipment
are also used in the process of permanently closing oil and natural gas wells at
the end of their productive lives. Plugging and abandonment work can be
performed with a well servicing rig along with wireline and cementing equipment.
The services generally include the sale or disposal of equipment salvaged from
the well as part of the compensation received and require compliance with state
regulatory requirements. The demand for oil and natural gas does not
significantly affect the demand for plugging and abandonment services, as well
operators are required by state regulations to plug a well that it is no longer
productive. The need for these services is also driven by lease and/or operator
policy requirements.
OILFIELD TRUCKING
Upon completion of the acquisition of QSI, Key has established itself as a
leading provider of liquid/ vacuum truck services and fluid transportation and
disposal services for operators whose wells produce saltwater and other fluids,
in addition to oil and natural gas. Of the 2,233 heavy oilfield service vehicles
operated by the Company following the acquisition of QSI, the Company operates
1,026 vacuum and transport trucks in the United States. In addition, Key owns
approximately 2,972 frac tanks which are used in conjunction with the fluid
hauling operations.
Fluid hauling trucks are utilized in connection with drilling and workover
projects, which tend to produce and use large amounts of various oilfield
fluids. Fluid hauling companies transport fresh water to the well site and
provide temporary storage and disposal of produced salt water and
drilling/workover fluids. These fluids are picked up at the well site and
transported for disposal in a salt water disposal well of which Key owns
approximately 130. In addition, Key provides haul/equipment trucks that are used
to move large pieces of equipment from one wellsite to the next and operates a
fleet of hot oilers. Demand and pricing for these services are generally related
to demand for Key's well service and drilling rigs. Fluid hauling and equipment
hauling services are typically priced on a per hour basis while frac tank
rentals typically are billed on a per day basis.
WELL INTERVENTION SERVICES
Through its acquisition of QSI in July 2002, Key expanded its fishing and
rental tool operations and added a pressure pumping business. These operations
comprise Key's Well Intervention Services Division which is part of the well
servicing line of business.
Founded in 1993, QSI's fishing and rental tool operation, Quality Tubular
Services, Inc. ("QTS"), provides fishing and rental tool services to major and
independent oil and natural gas production
8
companies primarily in the Gulf Coast region of the United States. QTS operates
nine 24-hour service locations and four regional sales offices. The fishing tool
supervisors have extensive experience with downhole problems. In addition, QTS
offers a full line of services and equipment designed for the harsh elements
from land to offshore. The rental tool inventory consists of tubulars, handling
tools, pressure-control equipment and a fleet of power swivels. Key also
provides fishing and rental tools through its Landmark Fishing and Rental Tools
operation in the Mid-Continent region and at various locations throughout the
country.
Key's pressure pumping business operates under the name American Energy
Services, Inc. ("AES"). AES provides stimulation services, cementing services,
nitrogen services, hydro-testing and production chemistry services to oil and
natural gas producers. Key offers a full complement of acidizing technology,
fracturing technology, nitrogen technology and cementing technology services.
With over 64,000 horsepower in cementing and stimulation equipment, AES is one
of the largest U.S. providers of pressure pumping services. AES was established
in December 1996 and operates in the Permian Basin, the San Juan Basin, and the
Mid-Continent Region.
ANCILLARY OILFIELD SERVICES
Key provides ancillary oilfield services, which include among others:
wireline; well site construction; roustabout services; and foam units and air
drilling services. Demand and pricing for these services are generally related
to demand for Key's well service and drilling rigs.
CONTRACT DRILLING
Key provides contract drilling services to major oil companies and
independent oil and natural gas producers onshore the continental United States
in the Permian Basin, the Four Corners region, Michigan, the Northeast, and the
Rocky Mountains and internationally in Argentina and Ontario, Canada. Contract
drilling services are primarily provided under standard dayrate, and, to a
lesser extent, footage or turnkey contracts. Drilling rigs vary in size and
capability and may include specialized equipment. The majority of Key's drilling
rigs is equipped with mechanical power systems and has depth ratings ranging
from approximately 4,500 to 12,000 feet. Key has one drilling rig with a depth
rating of approximately 18,000 feet. Like workover services, the demand for
contract drilling is directly related to expectations relating to, and changes
in, oil and natural gas prices which in turn, are driven by the supply of and
demand for these commodities.
FOREIGN OPERATIONS
Key also operates each of its business segments discussed above in
Argentina, Ontario, Canada and Egypt. Key's foreign operations currently own 25
well servicing rigs, 75 oilfield trucks and seven drilling rigs in Argentina,
four well servicing rigs, four oilfield trucks and two drilling rigs in Ontario,
Canada and five well servicing rigs in the Arab Republic of Egypt.
CUSTOMERS
Key's customers include major oil companies, independent oil and natural gas
production companies, and foreign national oil and natural gas production
companies. One customer in fiscal 2002, Occidental Petroleum Corporation,
accounted for 10% of Key's consolidated revenues.
COMPETITION AND OTHER EXTERNAL FACTORS
Despite the significant consolidation in the domestic well servicing
industry, there are numerous smaller companies that compete in Key's well
servicing markets. Nonetheless, Key believes that its performance, equipment,
safety, and availability of equipment to meet customer needs and availability of
experienced, skilled personnel is superior to that of its competitors.
9
In the well servicing markets, an important competitive factor in
establishing and maintaining long-term customer relationships is having an
experienced, skilled and well-trained work force. In recent years, many of Key's
larger customers have placed increased emphasis on the safety records and
quality of the crews, equipment and services provided by their contractors. Key
has, and will continue to devote substantial resources toward employee safety
and training programs. Management believes that many of Key's competitors,
particularly small contractors, have not undertaken similar training programs
for their employees. Management believes that Key's safety record and reputation
for quality equipment and service are among the best in the industry.
In the contract drilling market, Key competes with other regional and
national oil and natural gas drilling contractors, some of which have larger rig
fleets with greater average depth capabilities and a few that have better
capital resources than Key. Management believes that the contract drilling
industry is less consolidated than the well servicing industry, resulting in a
contract drilling market that is more price competitive. Nonetheless, Key
believes that it is competitive in terms of drilling performance, equipment,
safety, pricing, availability of equipment to meet customer needs and
availability of experienced, skilled personnel in those regions in which it
operates.
The need for well servicing and contract drilling fluctuates, primarily, in
relation to the price of oil and natural gas which, in turn, is driven by the
supply of and demand for oil and natural gas. As supply of those commodities
decreases and demand increases, service and maintenance requirements increase as
oil and natural gas producers attempt to maximize the producing efficiency of
their wells in a higher priced environment.
EMPLOYEES
As of June 30, 2002, Key employed approximately 7,850 persons (approximately
7,746 employees in its well servicing and contract drilling businesses and
approximately 104 employees on its corporate staff). Key's employees are not
represented by a labor union and are not covered by collective bargaining
agreements. Key has not experienced work stoppages associated with labor
disputes or grievances and considers its relations with its employees to be
satisfactory.
ENVIRONMENTAL REGULATIONS
Key's operations are subject to various local, state and federal laws and
regulations intended to protect the environment. Key's operations routinely
involve the handling of waste materials, some of which are classified as
hazardous substances. Consequently, the regulations applicable to Key's
operations include those with respect to containment, disposal and controlling
the discharge of any hazardous oilfield waste and other non-hazardous waste
material into the environment, requiring removal and cleanup under certain
circumstances, or otherwise relating to the protection of the environment. Laws
and regulations protecting the environment have become more stringent in recent
years, and may in certain circumstances impose "strict liability," rendering a
party liable for environmental damage without regard to negligence or fault on
the part of such party. Such laws and regulations may expose Key to liability
for the conduct of, or conditions caused by, others, or for Key's acts, which
were in compliance with all applicable laws at the times such acts were
performed. Cleanup costs and other damages arising as a result of environmental
laws, and costs associated with changes in environmental laws and regulations
could be substantial and could have a material adverse effect on Key's financial
condition. From time to time, claims have been made and litigation has been
brought against Key under such laws. However, the costs incurred in connection
with such claims and other costs of environmental compliance have not had any
material adverse effect on Key's operations or financial statements in the past,
and management is not currently aware of any situation or condition that it
believes is likely to have any such material adverse effect in the future.
Management believes that it conducts Key's operations in substantial compliance
with all material federal, state and local regulations as they relate to the
environment. Although Key has incurred certain costs in complying with
environmental laws and regulations, such amounts have not been material to Key's
financial results during the past three fiscal years.
10
ITEM 2. PROPERTIES.
Key's corporate headquarters are located in Midland, Texas. Key leases
office space at this location from an independent third party.
WELL SERVICING AND CONTRACT DRILLING
The following table sets forth the type, number and location of the major
equipment owned and operated by Key's operating divisions as of June 30, 2002:
WELL SERVICE AND OILFIELD DRILLING
OPERATING DIVISION WORKOVER RIGS TRUCKS RIGS
------------------ ---------------- -------- --------
DOMESTIC:
Permian Basin (well servicing).............. 468 450 --
Gulf Coast.................................. 252 319 --
Mid-Continent............................... 326 385 --
Four Corners................................ 49 91 15
Eastern..................................... 91 253 3
Rocky Mountains............................. 131 58 14
California.................................. 138 35 --
Key Energy Drilling (Permian Basin)......... 0 49 38
----- ----- --
DOMESTIC SUBTOTAL............................. 1,455 1,640 70
----- ----- --
INTERNATIONAL:
Argentina................................... 25 75 7
Canada...................................... 4 4 2
Egypt....................................... 2 -- --
----- ----- --
INTERNATIONAL SUBTOTAL........................ 31 79 9
----- ----- --
TOTALS........................................ 1,486 1,719 79
===== ===== ==
The Permian Basin Well Servicing division owns 36 and leases seven office
and yard locations. The Gulf Coast division owns 14 and leases six office and
yard locations. The Mid-Continent division owns 30 and leases 22 office and yard
locations. The Four Corners division owns six and leases two office and yard
locations. The Eastern division owns three and leases ten office and yard
locations. The Rocky Mountain division owns 18 and leases two office and yard
locations. The California division owns one and leases two office and yard
locations. The Permian Basin Drilling division owns two and leases two office
and yard locations. The Argentina division owns one and leases one office and
yard locations. The Canadian operation owns one yard location. Odessa
Exploration owns interests in 223 gross (172 proved developed) oil leases and 57
gross (50 proved developed) gas leases. The corporate division leases two office
locations in addition to its headquarters.
All operating facilities are one story office and/or shop buildings. All
buildings are occupied and considered to be in satisfactory condition.
ITEM 3. LEGAL PROCEEDINGS AND OTHER ACTIONS.
See Note 3 to Consolidated Financial Statements--Commitments and
Contingencies.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
11
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Key's common stock is currently traded on the New York Stock Exchange, under
the symbol "KEG". As of June 30, 2002, there were 645 registered holders of
110,308,463 issued and outstanding shares of common stock, including 416,666
shares of common stock held in treasury (109,891,797 net of treasury shares).
The following table sets forth, for the periods indicated, the high and low
sales prices of Key's common stock on the New York Stock Exchange for fiscal
2002 and fiscal 2001, as derived from published sources.
HIGH LOW
-------- --------
Fiscal Year Ending 2002:
Fourth Quarter............................................ $12.59 $9.63
Third Quarter............................................. 11.45 7.20
Second Quarter............................................ 9.70 5.99
First Quarter............................................. 11.01 5.58
Fiscal Year Ending 2001:
Fourth Quarter............................................ $15.33 $9.55
Third Quarter............................................. 13.52 8.13
Second Quarter............................................ 10.50 6.81
First Quarter............................................. 11.44 7.06
There were no dividends paid on Key's common stock during the fiscal years
ended June 30, 2002, 2001 or 2000. Key does not intend, for the foreseeable
future, to pay dividends on its common stock. In addition, Key is contractually
restricted from paying dividends under the terms of its existing credit
facilities.
RECENT SALES OF UNREGISTERED SECURITIES
Key did not make any unregistered sales of its securities during the twelve
months ended June 30, 2002 that were not previously included in its Quarterly
Reports filed for such period.
EQUITY COMPENSATION PLAN INFORMATION
The following table summarizes information, as of June 30, 2002, about the
Company's common stock that may be issued upon the exercise of options that have
been granted (i) under equity compensation plans that have been approved by the
Company's shareholders and (ii) outside such plans. The only equity compensation
plan that has been approved by the Company's shareholders is the Key Energy
Group, Inc. 1997 Incentive Plan (the "Incentive Plan"). For a description of the
Incentive Plan, see Note 8 to Consolidated Financial Statements--Stockholders'
Equity. All options not issued under the Incentive Plan (the "Non-Plan Options")
were approved by the Board or the Compensation Committee under individual option
grants (rather than under a separate equity compensation plan not approved by
the Company's shareholders). The Non-Plan Options (i) expire in ten years,
(ii) vest either on the grant date or ratably over a three-year period following
the grant date, (iii) have exercise prices equal to or greater than the
12
market price at the date of grant and (iv) have other terms similar to those
options granted under the Incentive Plan.
NUMBER OF SECURITIES
NUMBER OF SECURITIES REMAINING AVAILABLE FOR
TO BE ISSUED UPON FUTURE ISSUANCE UNDER
EXERCISE OF WEIGHTED-AVERAGE EQUITY COMPENSATION PLANS
OUTSTANDING OPTIONS, EXERCISE PRICE OF (EXCLUDING SECURITIES
WARRANTS, AND RIGHTS OUTSTANDING OPTIONS, REFLECTED IN COLUMN (A))
(THOUSANDS) WARRANTS, AND RIGHTS (THOUSANDS)
PLAN CATEGORY (A) (B) (C)
------------- -------------------- -------------------- -------------------------
Equity compensation plans approved by
the security holders............... 6,298 $7.41 616(1)
Equity compensation plans not
approved by the security holders... 3,710 $8.45 0(2)
Total................................ 10,008 $7.80 409
------------------------
(1) The number of shares of the Company's common stock available for issuance
under the Incentive Plan on any given date, subject to adjustment in certain
circumstances, is equal to (i) 10% of the number of shares of the Company's
common stock issued and outstanding on the last day of the calendar quarter
immediately preceding such date (provided, however, that such number cannot
decrease from one quarter to the next quarter), less (ii) the number of
shares of the Company's common stock previously granted under the Incentive
Plan through such date, plus (iii) the number of shares of the Company's
common stock previously granted under the Incentive Plan that have been
forfeited through such date.
(2) Because the Non-Plan Options are comprised of individual grants outside the
Incentive Plan, all shares available for issuance under the Non-Plan Options
are reflected in column (a).
13
ITEM 6. SELECTED FINANCIAL DATA.
FISCAL YEAR ENDED JUNE 30,
-------------------------------------------------------------
2002 2001 2000 1999(1) 1998
---------- ---------- ---------- ---------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
OPERATING DATA:
Revenues................................................. $ 802,564 $ 873,262 $ 637,732 $ 491,817 $ 424,543
Operating costs:
Direct costs(4)........................................ 554,773 582,154 471,169 374,308 296,328
Depreciation, depletion and amortization............... 78,265 75,147 70,972 62,074 31,001
General and administrative(4).......................... 59,494 60,118 51,637 56,156 36,933
Interest............................................... 43,332 56,560 71,930 67,401 21,476
Foreign currency transaction loss, Argentina........... 1,443 -- -- -- --
Debt issuance costs.................................... -- -- -- 6,307 --
Restructuring charge................................... -- -- -- 4,504 --
Income (loss) before income taxes, minority interest, and
extraordinary items.................................... 65,257 99,283 (27,976) (78,933) 38,805
Net income (loss)........................................ 38,146 62,710 (18,959) (53,258) 24,175
INCOME (LOSS) PER COMMON SHARE:
Basic.................................................. $ 0.36 $ 0.63 $ (0.23) $ (1.94) $ 1.41
Diluted................................................ $ 0.35 $ 0.61 $ (0.23) $ (1.94) $ 1.23
Average common shares outstanding:
Basic.................................................. 105,766 98,195 83,815 27,501 17,153
Assuming full dilution................................. 107,462 102,271 83,815 27,501 24,024
Common shares issued at period end....................... 110,308 101,440 97,210 82,738 18,267
Market price per common share at period end.............. $ 10.50 $ 10.84 $ 9.64 $ 3.56 $ 13.12
Cash dividends paid on common shares..................... -- -- -- -- --
BALANCE SHEET DATA:
Cash..................................................... $ 54,147 $ 2,098 $ 109,873 $ 23,478 $ 25,265
Current assets........................................... 192,073 206,150 253,589 132,543 127,557
Property and equipment................................... 1,093,104 1,014,675 920,437 871,940 547,537
Property and equipment, net.............................. 808,900 793,716 760,561 769,562 499,152
Total assets............................................. 1,242,995 1,228,284 1,246,265 1,148,138 698,640
Current liabilities...................................... 96,628 115,553 92,848 73,151 48,029
Long-term debt, including current portion................ 443,610 493,907 666,600 699,978 399,779
Stockholders' equity..................................... 536,866 476,878 382,887 288,094 154,928
OTHER DATA:
Adjusted EBITDA(2)....................................... 188,465 $ 232,253 $ 116,574 $ 67,281 $ 92,108
Net cash provided by (used in):
Operating activities................................... 178,716 143,347 34,860 (13,427) 40,925
Investing activities................................... (108,749) (83,980) (37,766) (294,654) (306,339)
Financing activities................................... (17,315) (167,142) 89,301 306,294 248,975
Working capital.......................................... 95,445 90,597 160,741 59,392 79,528
Book value per common share(3)........................... $ 4.87 $ 4.70 $ 3.94 $ 3.47 $ 8.48
------------------------------
(1) Financial data for the year ended June 30, 1999 includes the allocated
purchase price of Dawson Production Services, Inc. and the results of their
operations, beginning September 15, 1998.
(2) Adjusted EBITDA is net income before interest expense, income taxes,
depreciation, depletion and amortization, bad debt expense, debt issuance
costs charged to earnings, restructuring charge, foreign currency
transaction loss and extraordinary items. Adjusted EBITDA is presented
because of its acceptance as a component of a company's potential valuation
in comparison to companies in the same industry and of a company's ability
to service or incur debt. Management interprets trends indicated by changes
in adjusted EBITDA as an indicator of the effectiveness of its strategies in
achieving revenue growth and controlling direct and indirect costs of
services provided. Investors should consider that this measure does not take
into consideration debt service, interest expenses, costs of capital,
impairments of long lived assets, depreciation of property, the cost of
replacing equipment or income taxes. Adjusted EBITDA should not be
considered as an alternative to net income, income before taxes, cash flows
from operating activities or any other measure of financial performance
presented in accordance with generally accepted accounting principles and is
not intended to represent cash flow. Adjusted EBITDA may not be comparable
to similarly titled measures of other companies.
(3) Book value per common share is stockholders' equity at period end divided by
the number of issued common shares at period end.
(4) Includes unusual items of approximately $8.5 million for direct costs and
approximately $1.0 million for general and administrative during fiscal 2002
as previously discussed in the company's August 20, 2002 press release.
14
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION.
Special Note: Certain statements set forth below under this caption
constitute "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995. See "Special Note Regarding
Forward-Looking Statements" for additional factors relating to such statements.
The following discussion provides information to assist in the understanding
of the Company's financial condition and results of operations. It should be
read in conjunction with the consolidated financial statements and related notes
appearing elsewhere in this report. Certain reclassifications have been made to
the consolidated financial statements for the years ended June 30, 2001 and 2000
to conform to the year end June 30, 2002 presentation. The reclassifications
consist primarily of reclassifying certain items from general and administrative
expense to direct expense.
RESULTS OF OPERATIONS
FISCAL YEAR ENDED JUNE 30, 2002 VERSUS FISCAL YEAR ENDED JUNE 30, 2001
The Company's results of operations for the year ended June 30, 2002 reflect
the impact of a decline in industry conditions resulting from decreased
commodity prices (and its customers' perception that commodity prices may
decrease further) which in turn caused a decline in demand for the Company's
equipment and services partially offset by minimizing rate concessions and lower
interest charges during fiscal 2002 (see Part I--Item 1--Major Developments
During Fiscal 2002--Unfavorable Industry Conditions
THE COMPANY
Revenues for the year ended June 30, 2002 decreased $70,698,000, or 8.1%, to
$802,564,000 from $873,262,000 in fiscal 2001, while net income for fiscal 2002
decreased $24,564,000, or 39.2%, to $38,146,000 from a net income of $62,710,000
in fiscal 2001. The decrease in revenues and net income is due to lower levels
of activity partially offset by higher pricing, with lower interest expense from
debt reduction also contributing to net income.
OPERATING REVENUES
WELL SERVICING. Well servicing revenues for the year ended June 30, 2002
decreased $51,644,000, or 6.8%, to $706,629,000 from $758,273,000 in fiscal
2001. The decrease was due to lower demand for the Company's well servicing
equipment and services partially offset by higher pricing.
CONTRACT DRILLING. Contract drilling revenues for the year ended June 30,
2002 decreased $20,562,000, or 19.1%, to $87,077,000 from $107,639,000 in fiscal
2001. The decrease was due to lower demand for the Company's contract drilling
equipment and services partially offset by higher pricing.
OPERATING EXPENSES
WELL SERVICING. Well servicing expenses for the year ended June 30, 2002
decreased $10,643,000, or 2.1%, to $489,681,000 from $500,324,000 in fiscal
2001. The decrease in expenses is due to lower activity levels partially offset
by higher insurance costs primarily in workers compensation and health care.
Despite the decreased costs, well servicing expenses as a percentage of well
servicing revenues increased from 66.0% for fiscal 2001 to 69.3% for fiscal 2002
primarily due to the increase in insurance costs.
CONTRACT DRILLING. Contract drilling expenses for the year ended June 30,
2002, decreased $16,805,000, or 21.7%, to $60,561,000 from $77,366,000 in fiscal
2001. The decrease is due to lower activity levels partially offset by higher
insurance costs primarily in workers compensation and health care. Contract
drilling expenses as a percentage of contract drilling revenues decreased from
71.9% in fiscal
15
2001 to 69.5% in fiscal 2002. The margin improvement is due to improved
operating efficiencies and the effects of higher pricing partially offset by the
increase in insurance costs.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
The Company's depreciation, depletion and amortization expense for the year
ended June 30, 2002 increased $3,118,000, or 4.1%, to $78,265,000 from
$75,147,000 in fiscal 2001. The increase is due to recent acquisitions and
increased capital expenditures during the past year as the Company continued
major refurbishments of well servicing and contract drilling equipment partially
offset by discontinued amortization of goodwill, which amounted to $9,322,000 in
fiscal 2001, because of the Company's adoption of SFAS 142.
GENERAL AND ADMINISTRATIVE EXPENSES
The Company's general and administrative expenses for the year ended
June 30, 2002 decreased $624,000, or 1.0%, to $59,494,000 from $60,118,000 in
fiscal 2001. The decrease was due to reductions in incentive payroll costs
partially offset by additional expenses incurred as a result of moving the
corporate headquarters to Midland, Texas from East Brunswick, New Jersey and
increases in personnel supporting information technology functions. Despite the
decreased costs, general and administrative expenses as a percentage of total
revenues increased from 6.9% in fiscal 2001 to 7.4% in fiscal 2002.
INTEREST EXPENSE
The Company's interest expense for the year ended June 30, 2002 decreased
$13,228,000, or 23.4%, to $43,332,000 from $56,560,000 in fiscal 2001. The
decrease was primarily due to a significant reduction in the Company's long-term
debt using proceeds from the equity offering, the debt offering and operating
cash flow, and to a lesser extent, lower interest rates. Included in the
interest expense was the amortization of debt issuance costs of $2,581,000 and
$3,578,000 for the years ended June 30, 2002 and 2001, respectively.
FOREIGN CURRENCY TRANSACTION LOSS
During fiscal 2002, the Company recorded an Argentine foreign currency
transaction loss of approximately $1,443,000 related to dollar-denominated
receivables resulting from the recent devaluation of Argentina's currency.
EXTRAORDINARY GAIN (LOSS)
During fiscal 2002, the Company repurchased $150,908,000 of its long-term
debt at various discounts and premiums to par value and expensed related
unamortized debt issuance costs, all of which resulted in an after-tax
extraordinary loss of $3,037,000.
INCOME TAXES
The Company's income tax expense for the year ended June 30, 2002 decreased
$12,928,000 to $24,074,000 from $37,002,000 in fiscal 2001. The decrease in
income tax expense is due to decreased pre-tax income. The Company's effective
tax rate for fiscal 2002 and 2001 was 36.9% and 37.3%, respectively. The
effective tax rates vary from the statutory federal rate of 35% principally
because of the disallowance of certain goodwill amortization (for the year ended
June 30, 2001), and other non-deductible expenses and the effects of state and
local taxes.
16
CASH FLOW
The Company's net cash provided by operating activities for the year ended
June 30, 2002 increased $35,369,000 to $178,716,000 from $143,347,000 in fiscal
2001. The increase, despite lower net income in fiscal 2002, is primarily due to
a decrease in accounts receivable in fiscal 2002 compared to an increase in
accounts receivable in fiscal 2001.
The Company's net cash used in investing activities for the year ended
June 30, 2002 increased $24,769,000 to $108,749,000 from $83,980,000 in fiscal
2001. The increase is due primarily to higher capital expenditures and an
increase in acquisitions.
The Company's net cash used in financing activities for the year ended
June 30, 2002 decreased $149,827,000 to $17,315,000 from $167,142,000 in fiscal
2001. The decrease is primarily the result of higher proceeds from debt and
equity offerings in fiscal 2002 compared to fiscal 2001. While the Company
continued its strategy and significantly reduced debt in fiscal 2002, total debt
reductions in fiscal 2002 decreased compared to fiscal 2001.
The effect of exchange rates on cash for the year ended June 30, 2002 was a
use of $603,000. This was a result of the devaluation of the Argentine peso in
fiscal 2002.
FISCAL YEAR ENDED JUNE 30, 2001 VERSUS FISCAL YEAR ENDED JUNE 30, 2000
The Company's results of operations for the year ended June 30, 2001 reflect
the impact of favorable industry conditions resulting from increased commodity
prices which in turn caused increased demand for the Company's equipment and
services during fiscal 2001. The positive impact of this increased demand on the
Company's operating results was partially offset by increased operating expenses
incurred as a result of the increase in the Company's business activity.
THE COMPANY
Revenues for the year ended June 30, 2001 increased $235,530,000, or 36.9%,
to $873,262,000 from $637,732,000 in fiscal 2000, while net income for fiscal
2001 increased $81,669,000 to $62,710,000 from a net loss of $18,959,000 in
fiscal 2000. The increase in revenues and net income is due to improved
operating conditions, higher rig hours, and increased pricing, with lower
interest expense from debt reduction also contributing to net income.
OPERATING REVENUES
WELL SERVICING. Well servicing revenues for the year ended June 30, 2001
increased $198,781,000 or 35.5%, to $758,273,000 from $559,492,000 in fiscal
2000. The increase was due to increased demand for the Company's well servicing
equipment and services and higher pricing.
CONTRACT DRILLING. Contract drilling revenues for the year ended June 30,
2001 increased $39,211,000, or 57.3%, to $107,639,000 from $68,428,000 in fiscal
2000. The increase was due to increased demand for the Company's contract
drilling equipment and services and higher pricing.
OPERATING EXPENSES
WELL SERVICING. Well servicing expenses for the year ended June 30, 2001
increased $91,601,000, or 22.4%, to $500,324,000 from $408,723,000 in fiscal
2000. The increase in expenses is due to higher utilization of the Company's
well servicing equipment, higher labor costs and the overall increase in the
Company's well servicing business. Despite the increased costs, well servicing
expenses as a percent of well servicing revenues decreased from 73.1% for fiscal
2000 to 66.0% for fiscal 2001. The margin improvement is due to improved
operating efficiencies and the effects of higher pricing.
17
CONTRACT DRILLING. Contract drilling expenses for the year ended June 30,
2001, increased $19,067,000, or 32.7%, to $77,366,000 from $58,299,000 in fiscal
2000. The increase is due to higher utilization of the Company's contract
drilling equipment, higher labor costs and the overall increase in the Company's
contract drilling business. Despite the increased costs, contract drilling
expenses as a percentage of contract drilling revenues decreased from 85.2% in
fiscal 2000 to 71.9% in fiscal 2001. The margin improvement is due to improved
operating efficiencies and the effects of higher pricing.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
The Company's depreciation, depletion and amortization expense for the year
ended June 30, 2001 increased $4,175,000, or 5.9%, to $75,147,000 from
$70,972,000 in fiscal 2000. The increase is due to higher capital expenditures
incurred during fiscal 2001 as the Company refurbished equipment and increased
utilization of its contract drilling equipment (which it depreciates partially
based on utilization).
GENERAL AND ADMINISTRATIVE EXPENSES
The Company's general and administrative expenses for the year ended
June 30, 2001 increased $8,481,000, or 16.4%, to $60,118,000 from $51,637,000 in
fiscal 2000. The increase was due to higher administrative costs resulting from
the growth of the Company's operations as a result of improved industry
conditions. Despite the increased costs, general and administrative expenses as
a percentage of total revenues declined from 8.1% in fiscal 2000 to 6.9% in
fiscal 2001.
INTEREST EXPENSE
The Company's interest expense for the year ended June 30, 2001 decreased
$15,370,000, or 21.4%, to $56,560,000 from $71,930,000 in fiscal 2000. The
decrease was primarily due to the impact of the long-term debt reduction during
fiscal 2001 and, to a lesser extent, lower short-term interest rates and
borrowing margins on floating rate debt.
EXTRAORDINARY GAIN
During fiscal 2001, the Company repurchased $257,115,000 of its long-term
debt at various discounts and premiums to par value and expensed related
unamortized debt issue costs, all of which resulted in an after-tax
extraordinary gain of $429,000.
INCOME TAXES
The Company's income tax expense for the year ended June 30, 2001 increased
$44,408,000 to $37,002,000 from a benefit of $7,406,000 in fiscal 2000. The
increase in income tax expense is due to increased pre-tax income. The Company's
effective tax rate for fiscal 2001 and 2000 was 37.3% and (26.5)%, respectively.
The effective tax rates vary from the statutory federal rate of 35% principally
because of certain non-deductible goodwill amortization, other non-deductible
expenses and state and local taxes.
CASH FLOW
The Company's net cash provided by operating activities for the year ended
June 30, 2001 increased $108,487,000 to $143,347,000 from $34,860,000 in fiscal
2000. The increase is due to higher revenues resulting from increased demand for
the Company's equipment and services and higher pricing, partially offset by
higher operating and general and administrative expenses resulting from
increased business activity.
18
The Company's net cash used in investing activities for the year ended
June 30, 2001 increased $46,214,000 to $83,980,000 from $37,766,000 in fiscal
2000. The increase is due primarily to higher capital expenditures.
The Company's net cash used in financing activities for the year ended
June 30, 2001 increased $256,443,000 to a use of $167,142,000 from cash provided
of $89,301,000 in fiscal 2000. The increase is primarily the result of
significant debt reduction during fiscal 2001, partially offset by proceeds from
the Company's fiscal 2001 debt offering and the exercise of stock options and
warrants.
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically funded its operations, acquisitions, capital
expenditures and working capital requirements from cash flow from operations,
bank borrowings and the issuance of equity and long-term debt. The Company
believes that its current reserves of cash and cash equivalents, availability of
its existing credit lines, access to capital markets and internally generated
cash flow from operations are sufficient to finance the cash requirements of its
current and future operations.
The Company's cash and cash equivalents increased $52,049,000 to $54,147,000
as of June 30, 2002 from $2,098,000 as of June 30, 2001.
The Company expects to finance its capital expenditures using net cash
provided by operating activities and available credit. The Company believes that
its cash flow and, to the extent required, borrowings under its current and
future credit facilities, will be sufficient to fund such expenditures.
As of June 30, 2002 the Company had working capital (excluding the current
portion of long-term debt of $7,674,000) of approximately $103,119,000, which
includes cash and cash equivalents of approximately $54,147,000, as compared to
working capital (excluding the current portion of long-term debt of $7,946,000)
of approximately $98,543,000, which includes cash and cash equivalents of
approximately $2,098,000, as of June 30, 2001. The increase in working capital
is primarily due to an increase in cash and cash equivalents, a decrease in
accounts payable and is partially offset by a decrease in accounts receivable
and inventories.
LONG-TERM DEBT
Other than capital lease obligations and miscellaneous notes payable, as of
June 30, 2002, the Company's long-term debt was comprised of (i) a senior credit
facility, (ii) a series of 8 3/8% Senior Notes Due 2008, (iii) a series of 14%
Senior Subordinated Notes Due 2009, and (iv) a series of 5% Convertible
Subordinated Notes Due 2004.
SENIOR CREDIT FACILITY
During fiscal 2002, the Company had a senior credit facility (the "Prior
Senior Credit Facility") with a syndicate of banks led by PNC Bank, N.A. which
consisted of a $100,000,000 revolving loan facility. In addition, up to
$30,000,000 of letters of credit could be issued under the Prior Senior Credit
Facility, but any outstanding letters of credit reduced the borrowing
availability under the revolving loan facility. As of June 30, 2002, no funds
were outstanding under the revolving loan facility and approximately $27,963,000
of letters of credit related to workman's compensation insurance were
outstanding. The Company drew down approximately $43 million on January 14, 2002
in order to redeem the 14% Senior Subordinated Notes. The funds were repaid with
the issuance of additional 8 3/8% Notes in March 2002.
The revolving loan bore interest based upon, at the Company's option, the
prime rate plus a variable margin of 0.75% to 2.00% or a Eurodollar rate plus a
variable margin of 2.25% to 3.50%.
On July 15, 2002, the Company entered into a Third Amended and Restated
Credit Agreement (the "New Senior Credit Facility"). The New Senior Credit
Facility consists of a $150,000,000 revolving loan
19
facility with a $40,000,000 sublimit for letters of credit. The loans are
secured by most of the tangible and intangible assets of the Company. The
revolving loan commitment will terminate on July 15, 2005 and all revolving
loans must be paid on or before that date. The revolving loans bear interest
based upon, at the Company's option, the prime rate plus a variable margin of
0.00% to 0.75% or a Eurodollar rate plus a variable margin of 1.25% to 2.75%.
The New Senior Credit Facility has customary affirmative and negative covenants
including a maximum leverage ratio, a minimum fixed charge coverage ratio and a
minimum net worth, as well as limitations on liens and indebtedness and
restrictions on dividends, acquisitions and dispositions.
8 3/8% SENIOR NOTES
On March 6, 2001, the Company completed a private placement of $175,000,000
of 8 3/8% Senior Notes due 2008 (the "8 3/8% Senior Notes"). The net cash
proceeds from the private placement were used to repay all of the remaining
balance of the original term loans under the Senior Credit Facility, and a
portion of the revolving loan facility under the Senior Credit Facility then
outstanding. On March 1, 2002, the Company completed a public offering of an
additional $100,000,000 of 8 3/8% Senior Notes due 2008. The net cash proceeds
from the public offering were used to repay all of the remaining balance of the
revolving loan facility under the Senior Credit Facility. The 8 3/8% Senior
Notes are senior unsecured obligations. The 8 3/8% Senior Notes are effectively
subordinated to Key's secured indebtedness which includes borrowings under the
Senior Credit Facility.
On and after March 1, 2005, the Company may redeem some or all of the 8 3/8%
Senior Notes at any time at varying redemption prices in excess of par, plus
accrued interest. In addition, before March 1, 2004, the Company may redeem up
to 35% of the aggregate principal amount of the 8 3/8% Senior Notes with the
proceeds of certain sales of equity at 108.375% of par plus accrued interest.
At June 30, 2002, $275,000,000 principal amount of the 8 3/8% Senior Notes
remained outstanding. The 8 3/8% Senior Notes require semi-annual interest
payments on March 1 and September 1 of each year. Interest payments of
approximately $7,125,000 and $7,328,000 were paid on September 1, 2001 and
March 1, 2002, respectively.
14% SENIOR SUBORDINATED NOTES
On January 22, 1999, the Company completed the private placement of 150,000
units (the "Units") consisting of $150,000,000 of 14% Senior Subordinated Notes
due 2009 (the "14% Senior Subordinated Notes") and 150,000 warrants to purchase
2,173,433 shares of the Company's Common Stock at an exercise price of $4.88125
per share (the "Unit Warrants"). The net cash proceeds from the private
placement were used to repay substantially all of the remaining $148,600,000
principal amount (plus accrued interest) owed under the Company's bridge loan
facility arranged in connection with the acquisition of Dawson Production
Services, Inc. ("Dawson").
On and after January 15, 2004, the Company may redeem some or all of the 14%
Senior Subordinated Notes at any time at varying redemption prices in excess of
par, plus accrued interest. In addition, before January 15, 2002, the Company
was allowed to redeem up to 35% of the aggregate principal amount of the 14%
Senior Subordinated Notes at 114% of par plus accrued interest with the proceeds
of certain sales of equity. During fiscal 2001, the Company exercised its right
of redemption for $10,313,000 principal amount of the 14% Senior Subordinated
Notes at a price of 114% of the principal amount plus accrued interest. This
transaction resulted in an extraordinary loss before taxes of approximately
$2,561,000. On January 14, 2002, the Company exercised its right of redemption
for $35,403,000 principal amount of the 14% Senior Subordinated Notes at a price
of 114% of the principal amount plus accrued interest. This transaction resulted
in an extraordinary loss before taxes of approximately $8,468,000. Also, during
fiscal 2002, the Company purchased and canceled $6,784,000 principal amount of
the 14% Senior Subordinated Notes at a
20
price of 116% of the principal amount plus accrued interest. These transactions
resulted in extraordinary losses before taxes of approximately $1,821,000.
The Unit Warrants have separated from the 14% Senior Subordinated Notes and
became exercisable on January 25, 2000. On the date of issuance, the value of
the Unit Warrants was estimated at $7,434,000 and is classified as a discount to
the 14% Senior Subordinated Notes on the Company's consolidated balance sheet.
The discount is being amortized to interest expense over the term of the 14%
Senior Subordinated Notes. The 14% Senior Subordinated Notes mature and the Unit
Warrants expire on January 15, 2009. The 14% Senior Subordinated Notes are
subordinate to the Company's senior indebtedness, which includes borrowings
under the Senior Credit Facility and the 8 3/8% Senior Notes.
At June 30, 2002, $97,500,000 principal amount of the 14% Senior
Subordinated Notes remained outstanding. The 14% Senior Subordinated Notes pay
interest semi-annually on January 15 and July 15 of each year. Interest payments
of approximately $9,778,000 and $6,825,000 were made on July 15, 2001 and
January 15, 2002, respectively. As of June 30, 2002, 63,500 Unit Warrants had
been exercised, producing approximately $4,173,000 of proceeds to the Company
and leaving 86,500 Unit Warrants outstanding.
5% CONVERTIBLE SUBORDINATED NOTES
In late September and early October 1997, the Company completed a private
placement of $216,000,000 of 5% Convertible Subordinated Notes due 2004 (the "5%
Convertible Subordinated Notes"). The 5% Convertible Subordinated Notes are
subordinate to the Company's senior indebtedness which includes borrowings under
the Senior Credit Facility, the 14% Senior Subordinated Notes and the 8 3/8%
Senior Notes. The 5% Convertible Subordinated Notes are convertible, at the
holder's option, into shares of the Company's common stock at a conversion price
of $38.50 per share, subject to certain adjustments. The 5% Convertible
Subordinated Notes are redeemable, at the Company's option, on and after
September 15, 2000, in whole or part, together with accrued and unpaid interest.
The initial redemption price is 102.86% for the year beginning September 15,
2000 and declines ratably thereafter on an annual basis.
During fiscal 2001, the Company repurchased (and canceled) $47,384,000
principal amount of the 5% Convertible Subordinated Notes. These repurchases
resulted in extraordinary gains before taxes of approximately $4,564,000. During
fiscal 2002, the Company repurchased (and canceled) $108,475,000 principal
amount of the 5% Convertible Subordinated Notes, leaving $49,951,000 principal
amount of the 5% Convertible Subordinated Notes outstanding at June 30, 2002.
These repurchases resulted in extraordinary gains before taxes of approximately
$5,633,000. Since June 30, 2002, the Company has repurchased (and canceled) an
additional $204,000 principal amount of the 5% Convertible Subordinated Notes,
leaving $49,747,000 outstanding as of September 30, 2002. Interest on the 5%
Convertible Subordinated Notes is payable on March 15 and September 15 of each
year. Interest of approximately $3,027,000 and $1,259,000 was paid on
September 15, 2001 and March 15, 2002, respectively.
CRITICAL ACCOUNTING POLICIES
The Company follows certain significant accounting policies when preparing
its consolidated financial statements. A complete summary of these policies is
included in Note 1 to the consolidated financial statements included herein.
Certain of the policies require management to make significant and
subjective estimates which are sensitive to deviations of actual results from
management's assumptions. In particular, management makes estimates regarding
the fair value of the Company's reporting units in assessing potential
impairment of goodwill. In addition, the Company makes estimates regarding
future undiscounted cash flows from the future use of long-lived assets whenever
events or changes in circumstances indicate that the carrying amount of a
long-lived asset may not be recoverable.
21
In assessing impairment of goodwill, the Company has used estimates and
assumptions in estimating the fair value of its reporting units. Actual future
results could be different than the estimates and assumptions used. Events or
circumstances which might lead to an indication of impairment of goodwill would
include, but might not be limited to, prolonged decreases in expectations of
long-term well servicing and/or drilling activity or rates brought about by
prolonged decreases in oil or natural gas prices, changes in government
regulation of the oil and natural gas industry or other events which could
affect the level of activity of exploration and production companies.
In assessing impairment of long-lived assets other than goodwill where there
has been a change in circumstances indicating that the carrying amount of a
long-lived asset may not be recoverable, the Company has estimated future
undiscounted net cash flows from use of the asset based on actual historical
results and expectations about future economic circumstances including oil and
natural gas prices and operating costs. The estimate of future net cash flows
from use of the asset could change if actual prices and costs differ due to
industry conditions or other factors affecting the Company's performance.
RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS
Recently the Financial Accounting Standards Board, ("FASB") issued Statement
of Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations ("SFAS 143"), Statement of Financial Accounting Standards No. 144,
Accounting for the Impairment of Disposal of Long-Lived Assets ("SFAS 144"),
Statement of Financial Accounting Standards No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections ("SFAS 145") and Statement of Financial Accounting Standards
No. 146, Accounting for Costs Associated with Exit or Disposal Activities
("SFAS 146"). SFAS 143 requires the Company to recognize a liability for all
legal obligations associated with the retirement of tangible long lived assets
and capitalize and equal amount as a cost of the asset and depreciate it over
the estimated remaining useful life of the asset. The adoption of SFAS 143 could
have a material impact to the Company depending on the lives of its oil and gas
properties and salt water disposal wells. SFAS 144 addresses financial
accounting and reporting for the impairment of disposal of long-lived assets.
SFAS 145 rescinds Statement No. 4, which required all gains and losses from
extinguishment of debt to be aggregated and classified as an extraordinary item,
and amends Statement No. 13 to require that certain lease modifications that
have economic effects similar to sale-leaseback transactions be accounted for in
the same manner as sale-leaseback transactions. Upon adoption of SFAS 145, the
Company will no longer record the gains and losses from the extinguishment of
debt as extraordinary items. The impact of the adoption of SFAS 145 to the
Company will depend on the Company's early retirements of debt. SFAS 146
establishes requirements for financial accounting and reporting for costs
associated with exit or disposal activities. SFAS 143 is effective for fiscal
years beginning after June 15, 2002, with earlier adoption encouraged. SFAS 144
is effective for fiscal years beginning after December 15, 2001 and interim
periods within those fiscal years. SFAS 145 is effective for fiscal years
beginning after May 15, 2002, with earlier adoption encouraged. SFAS 146 is
effective for exit or disposal activities initiated after December 31, 2002. The
Company is currently assessing the impact of these standards on its consolidated
financial statements.
IMPACT OF INFLATION ON OPERATIONS
Management is of the opinion that inflation has not had a significant impact
on Key's business.
ITEM 7A. 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.
22
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about Key's potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in foreign currency exchange risk, interest rates
and oil and natural gas prices. The disclosures are not meant to be precise
indicators of expected future losses, but rather indicators of reasonably
possible losses. This forward-looking information provides indicators of how Key
views and manages its ongoing market risk exposures.
INTEREST RATE RISK
At June 30, 2002 Key had long-term debt outstanding of $443,610,000. Of this
amount, $420,781,000, or 94.9%, bears interest at fixed rates as follows:
BALANCE AT
JUNE 30, 2002
--------------
(THOUSANDS)
8 3/8% Senior Notes Due 2008................................ $276,433
14% Senior Subordinated Notes Due 2009...................... 94,257
5% Convertible Subordinated Notes Due 2004.................. 49,951
Other (at approximately 8%)................................. 140
--------
$420,781
========
The remaining $22,829,000 debt outstanding as of June 30, 2002 bears
interest at floating rates which averaged approximately 6.66% at June 30, 2002.
A 10% increase in short-term interest rates on the floating-rate debt
outstanding at June 30, 2002 would equal approximately 67 basis points. Such an
increase in interest rates would increase Key's fiscal 2003 interest expense by
approximately $200,000 assuming borrowed amounts remain outstanding.
The above sensitivity analysis for interest rate risk excludes accounts
receivable, accounts payable and accrued liabilities because of the short-term
maturity of such instruments.
FOREIGN CURRENCY RISK
During fiscal 2002, the Argentine government suspended the law tying the
Argentine peso to the U.S. dollar at the conversion ratio of 1:1 and created a
dual currency system in Argentina. Key's net assets of its Argentina
subsidiaries are based on the U.S. dollar equivalent of such amounts measured in
Argentine pesos as of December 31, 2001. Assets and liabilities of the Argentine
operations were translated to U.S. dollars at June 30, 2002 using the applicable
free market conversion ratio of 3.9:1 and will be translated at future dates
using the applicable free market conversion ratio on such dates. Key's net
earnings and cash flows from its Argentina subsidiaries were tied to the U.S.
dollar for the six months ended December 31, 2001 and are based on the U.S.
dollar equivalent of such amounts measured in Argentine pesos for periods after
December 31, 2001. Revenues, expenses and cash flow will be translated using the
average exchange rates during the periods after December 31, 2001. See Note 18
to the consolidated financial statements.
The change in the Argentine peso to the U.S. dollar exchange rate since
December 31, 2001 has reduced stockholders' equity by $48,383,000, through a
charge to other comprehensive loss through June 30, 2002.
Key's net assets, net earnings and cash flows from its Canadian subsidiary
are based on the U.S. dollar equivalent of such amounts measured in Canadian
dollars. Assets and liabilities of the Canadian operations are translated to
U.S. dollars using the applicable exchange rate as of the end of a reporting
period. Revenues and expenses are translated using the average exchange rate
during the reporting period.
A 10% change in the Canadian-to-U.S. Dollar exchange rate would not be
material to the net assets, net earnings or cash flows of the Company.
23
COMMODITY PRICE RISK
Key's major market risk exposure for its oil and natural gas production
operations is in the pricing applicable to its oil and natural gas sales.
Realized pricing is primarily driven by the prevailing worldwide price for crude
oil and spot market prices for natural gas. Pricing for oil and natural gas
production has been volatile and unpredictable for several years.
The Company periodically hedges a portion of its oil and natural gas
production through collar and option agreements. The purpose of the hedges is to
provide a measure of stability in the volatile environment of oil and natural
gas prices and to manage exposure to commodity price risk under existing sales
commitments. The Company's risk management objective is to lock in a range of
pricing for expected production volumes. This allows the Company to forecast
future earnings within a predictable range. The Company meets this objective by
entering into collar and option arrangements which allow for acceptable cap and
floor prices.
As of June 30, 2002, Key had oil and natural gas price collars and put
options in place, as detailed in the following table. The total fiscal 2002
hedged oil and natural gas volumes represent approximately 41% and 32%,
respectively, of expected 2002 calendar year total production. A 10% variation
in the market price of oil or natural gas from their levels at June 30, 2002
would have no material impact on the Company's net assets, net earnings or cash
flows (as derived from commodity option contracts).
The following table sets forth the future volumes hedged by year and the
weighted-average strike price of the option contracts at June 30, 2002 and 2001:
MONTHLY INCOME STRIKE PRICE
------------------- PER BBL/MMBTU
OIL GAS -------------------
(BBLS) (MMBTU) TERM FLOOR CAP FAIR VALUE
-------- -------- ----------------- -------- -------- ----------
At June 30, 2002
Oil Put............. 5,000 -- Mar 2002-Feb 2003 $22.00 -- $ 24,000
Oil Put............. 4,000 -- Mar 2003-Feb 2004 $21.00 -- $ 118,000
Gas Put............. -- 75,000 Mar 2002-Feb 2003 $ 3.00 -- $ 104,000
At June 30, 2001
Oil Collar.......... 5,000 -- Mar 2001-Feb 2002 $19.70 $23.70 $(115,000)
Oil Put............. 5,000 -- Mar 2002-Feb 2003 $22.00 -- $ 141,000
Gas Collar.......... -- 40,000 Mar 2001-Feb 2002 $ 2.40 $ 2.91 $(229,000)
Gas Put............. -- 75,000 Mar 2002-Feb 2003 $ 3.00 -- $ 894,000
(The strike prices for the oil collars and puts are based on the NYMEX spot
price for West Texas Intermediate; the strike prices for the natural gas collars
are based on the Inside FERC-West Texas Waha spot price; the strike price for
the natural gas put is based on the Inside FERC-El Paso Permian spot price.)
24
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Presented herein are the consolidated financial statements of Key Energy
Services, Inc. as of June 30, 2002 and 2001 and for the years ended June 30,
2002, 2001 and 2000.
Also included is the report of KPMG LLP, independent certified public
accountants, on such consolidated financial statements as of June 30, 2002 and
2001 and for the years ended June 30, 2002, 2001 and 2000.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
--------
Consolidated Balance Sheets................................. 26
Consolidated Statements of Operations....................... 27
Consolidated Statements of Comprehensive Income............. 28
Consolidated Statements of Cash Flows....................... 29
Consolidated Statements of Stockholders' Equity............. 30
Notes to Consolidated Financial Statements.................. 31
Independent Auditors' Report................................ 63
25
KEY ENERGY SERVICES, INC.
CONSOLIDATED BALANCE SHEETS
JUNE 30, 2002 JUNE 30, 2001
-------------- --------------
(THOUSANDS, EXCEPT SHARE DATA)
ASSETS
Current assets:
Cash and cash equivalents................................. $ 54,147 $ 2,098
Accounts receivable, net of allowance for doubtful
accounts, $3,969 and $4,082, at June 30, 2002 and
June 30, 2001, respectively............................. 117,907 177,016
Inventories............................................... 7,776 16,547
Prepaid expenses and other current assets................. 12,243 10,489
---------- ----------
Total current assets........................................ 192,073 206,150
---------- ----------
Property and equipment:
Well servicing equipment.................................. 776,271 723,724
Contract drilling equipment............................... 124,191 119,122
Motor vehicles............................................ 68,977 64,907
Oil and gas properties and other related equipment,
successful efforts method............................... 44,439 44,245
Furniture and equipment................................... 38,979 24,865
Buildings and land........................................ 40,247 37,812
---------- ----------
Total property and equipment................................ 1,093,104 1,014,675
Accumulated depreciation & depletion........................ (284,204) (220,959)
---------- ----------
Net property and equipment.................................. 808,900 793,716
---------- ----------
Goodwill, net of accumulated amortization, $27,856 and
$28,168, at June 30, 2002 and June 30, 2001,
respectively............................................ 201,069 189,875
Deferred costs, net....................................... 12,580 17,624
Notes receivable--related parties......................... 274 6,050
Other assets.............................................. 28,099 14,869
---------- ----------
Total assets................................................ $1,242,995 $1,228,284
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 24,625 $ 42,544
Other accrued liabilities................................. 49,465 48,923
Accrued interest.......................................... 14,864 16,140
Current portion of long-term debt......................... 7,674 7,946
---------- ----------
Total current liabilities................................... 96,628 115,553
---------- ----------
Long-term debt, less current portion........................ 420,717 470,578
Capital lease obligations, less current portion............. 15,219 15,383
Deferred revenue............................................ 10,001 14,104
Non-current accrued expenses................................ 13,574 8,388
Deferred tax liability...................................... 149,990 127,400
Commitments and contingencies
Stockholders' equity:
Common stock, $0.10 par value; 200,000,000 shares
authorized, 110,308,463 and 101,440,166 shares issued,
respectively at June 30, 2002 and June 30, 2001,
respectively............................................ 11,031 10,144
Additional paid-in capital................................ 514,752 444,768
Treasury stock, at cost; 416,666 shares at June 30, 2002
and June 30, 2001....................................... (9,682) (9,682)
Accumulated other comprehensive income (loss)............. (48,967) 62
Retained earnings......................................... 69,732 31,586
---------- ----------
Total stockholders' equity.................................. 536,866 476,878
---------- ----------
Total liabilities and stockholders' equity.................. $1,242,995 $1,228,284
========== ==========
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
26
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED JUNE 30,
------------------------------------
2002 2001 2000
---------- ---------- ----------
(THOUSANDS, EXCEPT PER SHARE DATA)
REVENUES:
Well servicing............................................ $706,629 $758,273 $559,492
Contract drilling......................................... 87,077 107,639 68,428
Other..................................................... 8,858 7,350 9,812
-------- -------- --------
Total revenues.............................................. 802,564 873,262 637,732
-------- -------- --------
COSTS AND EXPENSES:
Well servicing............................................ 489,681 500,324 408,723
Contract drilling......................................... 60,561 77,366 58,299
Depreciation, depletion and amortization.................. 78,265 75,147 70,972
General and administrative................................ 59,494 60,118 51,637
Interest.................................................. 43,332 56,560 71,930
Other expenses............................................ 4,531 4,464 4,147
Foreign currency transaction loss, Argentina.............. 1,443 -- --
-------- -------- --------
Total costs and expenses.................................... 737,307 773,979 665,708
-------- -------- --------
Income (loss) before income taxes........................... 65,257 99,283 (27,976)
Income tax benefit (expense)................................ (24,074) (37,002) 7,406
-------- -------- --------
INCOME (LOSS) BEFORE EXTRAORDINARY GAIN (LOSS).............. 41,183 62,281 (20,570)
Extraordinary gain (loss) on retirement of debt, less
applicable income taxes of $1,775--2002, $(255)--2001 and
$(580)--2000.............................................. (3,037) 429 1,611
-------- -------- --------
NET INCOME (LOSS)........................................... $ 38,146 $ 62,710 $(18,959)
======== ======== ========
EARNINGS (LOSS) PER SHARE :
Basic--before extraordinary gain (loss)................... $ 0.39 $ 0.63 $ (0.25)
Extraordinary gain (loss) on retirement of debt, net of
tax..................................................... (0.03) -- 0.02
-------- -------- --------
Basic--after extraordinary gain (loss).................... $ 0.36 $ 0.63 $ (0.23)
======== ======== ========
Diluted--before extraordinary gain (loss)................. $ 0.38 $ 0.61 $ (0.25)
Extraordinary gain (loss) on retirement of debt, net of
tax..................................................... (0.03) -- 0.02
-------- -------- --------
Diluted--after extraordinary gain (loss).................. $ 0.35 $ 0.61 $ (0.23)
======== ======== ========
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic..................................................... 105,766 98,195 83,815
Diluted................................................... 107,462 102,271 83,815
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
27
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEAR ENDED JUNE 30,
------------------------------
2002 2001 2000
-------- -------- --------
(THOUSANDS)
NET INCOME (LOSS)........................................... $ 38,146 $62,710 $(18,959)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Derivative transition adjustment (See Note 6)............. -- (778) --
Oil and natural gas derivatives adjustment (See Note 6)... (279) 306 --
Amortization of oil and natural gas derivatives (See
Note 6)................................................. (367) 558 --
Currency translation gain (loss) (See Note 17)............ (48,383) (32) (1)
-------- ------- --------
COMPREHENSIVE INCOME (LOSS), NET OF TAX..................... $(10,883) $62,764 $(18,960)
======== ======= ========
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
28
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED JUNE 30,
--------------------------------
2002 2001 2000
--------- --------- --------
(THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ 38,146 $ 62,710 $(18,959)
ADJUSTMENTS TO RECONCILE INCOME FROM OPERATIONS TO NET
CASH PROVIDED BY (USED IN) OPERATIONS:
Depreciation, depletion and amortization.................. 78,265 75,147 70,972
Amortization of deferred debt issuance costs, discount and
premium................................................. 3,005 4,947 5,919
Deferred income taxes..................................... 23,160 34,698 (1,818)
(Gain) loss on sale of assets............................. (668) 173 25
Foreign currency transaction loss, Argentina.............. 1,443 -- --
Extraordinary (gain) loss, net of tax..................... 3,037 (429) (1,611)
CHANGE IN ASSETS AND LIABILITIES NET OF EFFECTS FROM THE
ACQUISITIONS:
(Increase) decrease in accounts receivable.............. 48,907 (53,813) (31,205)
(Increase) decrease in other current assets............. (4,410) (4,485) (5,483)
Increase (decrease) in accounts payable, accrued
interest and accrued expenses......................... (12,180) 29,414 18,875
Other assets and liabilities............................ 11 (5,015) (1,855)
--------- --------- --------
Net cash provided by (used in) operating activities....... 178,716 143,347 34,860
--------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures--well servicing...................... (57,857) (51,064) (26,469)
Capital expenditures--contract drilling................... (19,861) (15,884) (8,282)
Capital expenditures--other............................... (15,979) (15,802) (3,422)
Proceeds from sale of fixed assets........................ 4,258 3,415 2,722
Notes receivable from related parties..................... -- (1,500) (2,315)
Acquisitions--well servicing.............................. (17,273) (2,345) --
Acquisitions--contract drilling........................... (2,037) (800) --
--------- --------- --------
Net cash provided by (used in) investing activities....... (108,749) (83,980) (37,766)
--------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of long-term debt............................... (309,559) (373,998) (39,438)
Repayment of capital lease obligations.................... (10,182) (8,542) (11,639)
Proceeds from equity offerings, net of expenses........... 42,590 -- 100,571
Proceeds from long-term debt.............................. 258,500 205,210 12,000
Proceeds paid for debt issuance costs..................... (1,585) (4,958) --
Proceeds from forward sale, net of expenses............... -- -- 18,236
Proceeds from exercise of warrants........................ -- 847 8,473
Proceeds from exercise of stock options................... 3,219 14,617 1,098
Other..................................................... (298) (318) --
--------- --------- --------
Net cash provided by (used in) financing activities....... (17,315) (167,142) 89,301
--------- --------- --------
Effect of exchange rates on cash.......................... (603) -- --
Net increase (decrease) in cash........................... 52,049 (107,775) 86,395
Cash and cash equivalents at beginning of period.......... 2,098 109,873 23,478
--------- --------- --------
Cash and cash equivalents at end of period................ $ 54,147 $ 2,098 $109,873
========= ========= ========
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
29
KEY ENERGY SERVICES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(THOUSANDS)
COMMON STOCK ACCUMULATED
-------------------- ADDITIONAL OTHER
NUMBER AMOUNT PAID-IN TREASURY COMPREHENSIVE RETAINED
OF SHARES AT PAR CAPITAL STOCK INCOME EARNINGS TOTAL
--------- -------- ---------- -------- -------------- -------- --------
BALANCE AT JUNE 30, 1999.................. 83,155 $ 8,317 $301,615 $(9,682) $ 9 $(12,165) $288,094
------- ------- -------- ------- -------- -------- --------
Foreign currency transition adjustment,
net of tax.............................. -- -- -- -- (1) -- (1)
Exercise of warrants...................... 2,431 243 8,230 -- -- -- 8,473
Exercise of options....................... 241 24 1,074 -- -- -- 1,098
Conversion of 7% Debentures............... 380 38 3,568 -- -- -- 3,606
Issuance of common stock in equity
offering, net of offering costs......... 11,000 1,100 99,471 -- -- -- 100,571
Other..................................... 3 1 4 -- -- -- 5
Net income (loss)......................... -- -- -- -- -- (18,959) (18,959)
------- ------- -------- ------- -------- -------- --------
BALANCE AT JUNE 30, 2000.................. 97,210 $ 9,723 $413,962 $(9,682) $ 8 $(31,124) $382,887
------- ------- -------- ------- -------- -------- --------
Derivative transition adjustment (see
Note 6)................................. -- -- -- -- (778) -- (778)
Oil and natural gas derivatives
adjustment, net of tax (See Note 6)..... -- -- -- -- 306 -- 306
Amortization of oil and natural gas
derivatives (see Note 6)................ -- -- -- -- 558 -- 558
Foreign currency translation adjustment,
net of tax.............................. -- -- -- -- (32) -- (32)
Exercise of warrants...................... 185 19 828 -- -- -- 847
Exercise of options....................... 3,106 308 14,309 -- -- -- 14,617
Conversion of 7% Debentures............... 101 10 947 -- -- -- 957
Issuance of common stock for
acquisitions............................ 838 84 8,036 -- -- -- 8,120
Deferred tax benefit-compensation
expense................................. -- -- 7,004 -- -- -- 7,004
Other..................................... -- -- (318) -- -- -- (318)
Net income (loss)......................... -- -- -- -- -- 62,710 62,710
------- ------- -------- ------- -------- -------- --------
BALANCE AT JUNE 30, 2001.................. 101,440 $10,144 $444,768 $(9,682) $ 62 $31,586 $476,878
======= ======= ======== ======= ======== ======== ========
Oil and natural gas derivatives
adjustment, net of tax (See Note 6)..... -- -- -- -- (279) -- (279)
Amortization of oil and natural gas
derivatives (see Note 6)................ -- -- -- -- (367) -- (367)
Foreign currency translation adjustment,
net of tax.............................. -- -- -- -- (48,383) -- (48,383)
Exercise of warrants...................... 7 1 (1) -- -- -- --
Exercise of options....................... 659 66 3,153 -- -- -- 3,219
Issuance of common stock for
acquisitions............................ 2,801 280 24,787 -- -- -- 25,067
Issuance of common stock in equity
offering, net of offering costs......... 5,400 540 42,050 -- -- -- 42,590
Other..................................... 1 -- (5) -- -- -- (5)
Net income (loss)......................... -- -- -- -- -- 38,146 38,146
------- ------- -------- ------- -------- -------- --------
BALANCE AT JUNE 30, 2002.................. 110,308 $11,031 $514,752 $(9,682) $(48,967) $69,732 $536,866
======= ======= ======== ======= ======== ======== ========
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
30
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2002, 2001 AND 2000
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
THE COMPANY
Key Energy Services, Inc. (the "Company" or "Key"), is the largest onshore,
rig-based well servicing contractor in the world, with approximately 1,486 well
service rigs and 1,719 oilfield service vehicles as of June 30, 2002. The
Company provides a complete range of well services to major oil companies and
independent oil and natural gas production companies, including: rig-based well
maintenance, workover, completion, and recompletion services (including
horizontal recompletions); oilfield trucking services; and ancillary oilfield
services. Key conducts well servicing operations onshore the continental United
States in the following regions: Gulf Coast (including South Texas, Central Gulf
Coast of Texas, and South Louisiana), Permian Basin of West Texas and Eastern
New Mexico, Mid-Continent (including the Anadarko, Hugoton and Arkoma Basins,
and the ArkLaTex region), Four Corners (including the San Juan, Piceance, Uinta,
and Paradox Basins), Eastern (including the Appalachian, Michigan and Illinois
Basins), Rocky Mountains (including the Denver-Julesberg, Powder River, Wind
River, Green River and Williston Basins), and California (the San Joaquin
Basin), and internationally in Argentina and Ontario, Canada. The Company is
also a leading onshore drilling contractor, with 79 land drilling rigs as of
June 30, 2002. Key conducts land drilling operations in a number of major
domestic producing basins, as well as in Argentina and in Ontario, Canada. Key
also produces and develops oil and natural gas reserves in the Permian Basin
region and Texas Panhandle.
BASIS OF PRESENTATION
The Company's consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries. All significant inter-company
transactions and balances have been eliminated. The accounting policies
presented below have been followed in preparing the accompanying consolidated
financial statements.
ESTIMATES AND UNCERTAINTIES
Preparation of the accompanying consolidated financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amount of assets and
liabilities and disclosures of contingent assets and liabilities at the date of
the consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
INVENTORIES
Inventories, which consist primarily of oilfield service parts and supplies
held for consumption, are valued at the lower of average cost or market.
31
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
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%.
The Company uses the units-of-production method to depreciate its drilling
rigs. This method takes into consideration the number of days the rigs are
actually in service each month and depreciation is recorded for at least 15 days
each month for each rig that is available for service. The Company believes that
this method appropriately reflects its financial results by matching revenues
with expenses and appropriately reflects how the assets are to be used over
time.
The Company uses the successful efforts method of accounting for its oil and
gas properties. Under this method, all costs associated with productive wells
and nonproductive development wells are capitalized, while nonproductive
exploration costs and geological and geophysical costs (if any), are expensed.
Capitalized costs relating to proved properties are depleted using the
units-of-production method. The Company does not provide disclosures on its oil
and gas properties in accordance with FASB Statement No. 69, Disclosures about
Oil and Gas Producing Activities.
The Company follows the provisions of FASB Statement No. 121, Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.
This statement requires that long-lived assets including certain identifiable
intangibles, held and used by the Company, be reviewed for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. For purposes of applying this statement, the Company
groups its long-lived assets on a yard-by-yard basis and compares the estimated
future cash flows of each yard to the yard's net carrying value. The Company
would record an impairment charge, reducing the yard's net carrying value to an
estimated fair value, if the estimated future cash flows were less than the
yard's net carrying value. No impairment charges have been required.
32
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
The Company uses derivative financial instruments, primarily commodity
option contracts to reduce the exposure of its oil and gas producing operations
to changes in the market price of natural gas and crude oil and to fix the price
for natural gas and crude oil independently of the physical sale.
The financial instruments that the Company accounts for as hedging contracts
must meet the following criteria: the underlying asset or liability must expose
the Company to price risk that is not offset in another asset or liability, the
hedging contract must reduce that price risk, and the instrument must be
designated as a hedge at the inception of the contract and throughout the
contract period. In order to qualify as a hedge, there must be clear correlation
between changes in the fair value of the financial instrument and the fair value
of the underlying asset or liability such that changes in the market value of
the financial instrument will be offset by the effect of price rate changes on
the exposed items.
Prior to the adoption of SFAS 133, premiums paid for commodity option
contracts, which qualify as hedges, are amortized to oil and natural gas sales
over the terms of the contracts. Unamortized premiums are included in other
assets in the consolidated balance sheet. Amounts receivable under the commodity
option contracts are accrued as an increase in oil and natural gas sales for the
applicable periods.
Effective July 1, 2000, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133") as amended by SFAS
No. 137 and No. 138 ("SFAS 138"). SFAS 133 establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts and hedging activities. It requires the recognition
of all derivative instruments as assets and liabilities in the Company's balance
sheet and measurement of those instruments at fair value. The accounting
treatment of changes in fair value is dependent upon whether or not a derivative
instrument is designated as a hedge and if so, the type of hedge. For
derivatives designated as cash flow hedges, changes in fair value are recognized
in other comprehensive income until the hedged item is recognized in earnings.
See Note 6.
COMPREHENSIVE INCOME
The Company follows the provisions of Statement of Financial Accounting
Standards No. 130, "Reporting Comprehensive Income" ("SFAS 130"). SFAS 130
establishes standards for reporting and presentation of comprehensive income and
its components. SFAS 130 requires that all items that are required to be
recognized under accounting standards as components of comprehensive income be
reported in a financial statement that is displayed with the same prominence as
other financial statements. In accordance with the provisions of SFAS 130, the
Company has presented the components of comprehensive income in its Consolidated
Statements of Comprehensive Income.
ENVIRONMENTAL
The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which are constantly changing, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the adverse environmental effects of the disposal or release
of petroleum or chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past operations and
that have no future economic benefits are expensed. Liabilities for
33
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
expenditures of a non-capital nature are recorded when environmental assessment
and/or remediation is probable, and the costs can be reasonably estimated.
GOODWILL AND OTHER INTANGIBLE ASSETS
The Company has adopted Statement of Financial Accounting Standards No. 142,
Goodwill and Other Intangible Assets ("SFAS 142") on July 1, 2001. SFAS 142
eliminates the amortization for goodwill and other intangible assets with
indefinite lives. Intangible assets with lives restricted by contractual, legal,
or other means will continue to be amortized over their useful lives. Goodwill
and other intangible assets not subject to amortization are tested for
impairment annually or more frequently if events or changes in circumstances
indicate that the asset might be impaired. SFAS 142 requires a two-step process
for testing impairment. First, the fair value of each reporting unit is compared
to its carrying value to determine whether an indication of impairment exists.
If impairment is indicated, then the fair value of the reporting unit's goodwill
is determined by allocating the unit's fair value to its assets and liabilities
(including any unrecognized intangible assets) as if the reporting unit had been
acquired in a business combination. The amount of impairment for goodwill is
measured as the excess of its carrying value over its fair value. The Company
completed its assessment of goodwill impairment as of the date of adoption
during the three months ended December 31, 2001, as allowed by SFAS 142, and a
subsequent annual impairment assessment as of June 30, 2002. The assessments did
not result in an indication of goodwill impairment as of either date.
Intangible assets subject to amortization under SFAS 142 consist of
noncompete agreements. Amortization expense is calculated using the
straight-line method over the period of the agreement, ranging from three to
five years.
The gross carrying amount of noncompete agreements subject to amortization
totaled approximately $11,727,000 and $8,324,000 at June 30, 2002 and 2001,
respectively. Accumulated amortization related to these intangible assets
totaled approximately $6,130,000 and $4,953,000 at June 30, 2002 and 2001,
respectively. Amortization expense for the years ended June 30, 2002, 2001 and
2000 was approximately $1,914,000, $1,801,000 and $1,410,000, respectively.
Amortization expense for the next five succeeding fiscal years is estimated to
be $2,126,000, $1,143,000, $968,000, $797,000 and $513,000.
The Company has identified its reporting segments to be well servicing and
contract drilling. Goodwill allocated to such reporting segments at June 30,
2002 is $186,819,000 and $14,250,000, respectively. The change in the carrying
amount of goodwill for the year ended June 30, 2002 of $11,194,000 relates
principally to goodwill from well servicing assets acquired during the period
and the translation adjustment for Argentina.
34
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
The effects of the adoption of SFAS 142 on net income and earnings per share
for the years ended June 30, 2001 and 2000 are as follows:
YEAR ENDED JUNE 30,
-----------------------
2001 2000
---------- ----------
(THOUSANDS, EXCEPT PER
SHARE DATA)
Reported net income (loss) before extraordinary gain
(loss)................................................. $62,281 $(20,570)
Add back: goodwill amortization.......................... 9,322 9,840
------- --------
Adjusted net income (loss) before extraordinary gain
(loss)................................................. 71,603 (10,730)
Extraordinary gain, net of tax........................... 429 1,611
------- --------
Adjusted net income (loss)............................... $72,032 $ (9,119)
======= ========
BASIC EARNINGS (LOSS) PER SHARE:
Reported net income (loss) before extraordinary gain
(loss)................................................. $ 0.63 $ (0.25)
Add back: goodwill amortization.......................... 0.09 0.12
------- --------
Adjusted net income (loss) before extraordinary gain
(loss)................................................. 0.72 (0.13)
Extraordinary gain, net of tax........................... -- 0.02
------- --------
Adjusted net income (loss)............................... $ 0.72 $ (0.11)
======= ========
DILUTED EARNINGS (LOSS) PER SHARE:
Reported net income (loss) before extraordinary gain
(loss)................................................. $ 0.61 $ (0.25)
Add back: goodwill amortization.......................... 0.09 0.12
------- --------
Adjusted net income (loss)before extraordinary gain
(loss)................................................. 0.70 (0.13)
Extraordinary gain, net of tax........................... -- 0.02
------- --------
Adjusted net income (loss)............................... $ 0.70 $ (0.11)
======= ========
DEFERRED COSTS
Deferred costs totaling $32,928,000 and $31,052,000 at June 30, 2002 and
2001, respectively, represent debt issuance costs and are recorded net of
accumulated amortization of $20,348,000 and $13,428,000 at June 30, 2002 and
2001, respectively. Deferred costs are amortized to interest expense using the
straight-line method over the life of each applicable debt instrument or to
extraordinary loss as related debt is retired early. This method approximates
the amortization which would be recorded using the effective interest method.
Amortization of deferred costs totaled approximately $2,581,000, $3,578,000 and
$5,176,000 for fiscal 2002, 2001 and 2000, respectively. Unamortized debt
issuance costs written off and included in the determination of the
extraordinary loss on retirement of debt, before tax, for fiscal 2002, totaled
approximately $4,339,000 and the extraordinary gain on retirement of debt,
before tax, for fiscal 2001, totaled approximately $2,583,000.
35
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
INCOME TAXES
The Company accounts for income taxes based upon Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"). Under
SFAS 109, deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using statutory tax
rates expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rate is recognized in income in the
period that includes the statutory enactment date. A valuation allowance for
deferred tax assets is recognized when it is more likely than not that the
benefit of deferred tax assets will not be realized.
The Company and its eligible subsidiaries file a consolidated U. S. federal
income tax return. Certain subsidiaries that are consolidated for financial
reporting purposes are not eligible to be included in the consolidated U. S.
federal income tax return and separate provisions for income taxes have been
determined for these entities or groups of entities.
EARNINGS PER SHARE
The Company presents earnings per share information in accordance with the
provisions of Statement of Financial Accounting Standards No. 128, "Earnings per
Share" ("SFAS 128"). Under SFAS 128, basic earnings per common share are
determined by dividing net earnings applicable to common stock by the weighted
average number of common shares actually outstanding during the year. Diluted
earnings per
36
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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,
------------------------------------
2002 2001 2000
---------- ---------- ----------
(THOUSANDS, EXCEPT PER SHARE DATA)
BASIC EPS COMPUTATION:
NUMERATOR
Net income (loss) before extraordinary gain
(loss)............................................ $ 41,183 $ 62,281 $(20,570)
Extraordinary gain (loss), net of tax............... (3,037) 429 1,611
-------- -------- --------
Net income (loss)................................... $ 38,146 $ 62,710 $(18,959)
======== ======== ========
DENOMINATOR
Weighted average common shares outstanding.......... 105,766 98,195 83,815
-------- -------- --------
BASIC EPS:
Before extraordinary gain (loss).................... $ 0.39 $ 0.63 $ (0.25)
Extraordinary gain (loss), net of tax............... (0.03) -- 0.02
-------- -------- --------
Net income (loss)................................... $ 0.36 $ 0.63 $ (0.23)
======== ======== ========
DILUTED EPS COMPUTATION:
NUMERATOR
Net income (loss) before extraordinary gain (loss)
and effect of dilutive securities, tax effected... $ 41,183 $ 62,281 $(20,570)
Convertible securities.............................. -- 5 --
-------- -------- --------
Net income (loss) before extraordinary gain
(loss)............................................ 41,183 62,286 (20,570)
Extraordinary gain (loss), net of tax............... (3,037) 429 1,611
-------- -------- --------
Net income (loss)................................... $ 38,146 $ 62,715 $(18,959)
======== ======== ========
DENOMINATOR
Weighted average common shares outstanding.......... 105,766 98,195 83,815
Warrants.......................................... 402 205 --
Stock options..................................... 1,294 3,853 --
7% Convertible Debentures......................... -- 18 --
-------- -------- --------
107,462 102,271 83,815
-------- -------- --------
DILUTED EPS:
Before extraordinary gain (loss).................... $ 0.38 $ 0.61 $ (0.25)
Extraordinary gain (loss), net of tax............... (0.03) -- 0.02
-------- -------- --------
Net income (loss)................................... $ 0.35 $ 0.61 $ (0.23)
======== ======== ========
The diluted earnings per share calculation for the years ended June 30, 2002
and 2001 excludes the effect of the potential exercise of stock options of
1,177,000 and 360,000, respectively, and the potential
37
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
conversion of the Company's 5% Convertible Subordinated Notes because the
effects of such instruments on earnings per share would be anti-dilutive.
The diluted earnings per share calculation for the year ended June 30, 2000
excludes the effect of the potential conversion of all of the Company's then
outstanding convertible debt and the potential exercise of all of the Company's
then outstanding warrants and stock options because the effects of such
instruments on loss per share would be anti-dilutive.
CONCENTRATION OF CREDIT RISK
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist primarily of temporary cash investments
and trade receivables. The Company restricts investment of temporary cash
investments to financial institutions with high credit standing and, by policy,
limits the amount of credit exposure to any one financial institution. The
Company's customer base consists primarily of multi-national and independent oil
and natural gas producers. This may affect the Company's overall exposure to
credit risk either positively or negatively in as much as its customers are
affected by economic conditions in the oil and gas industry, which have
historically been cyclical. However, account receivables are well diversified
among many customers and a significant portion of the receivables are from major
oil companies, which management believes minimizes potential credit risk.
Historically, credit losses have been insignificant. Receivables are generally
not collateralized, although the Company may generally secure a receivable at
any time by filing a mechanic's or material-man's lien on the well serviced. The
Company maintains reserves for potential credit losses, and such losses have
been within management's expectations.
Key's customers include major oil companies, independent oil and natural gas
production companies, and foreign national oil and natural gas production
companies. One customer in fiscal 2002, Occidental Petroleum Corporation,
accounted for 10% of Key's consolidated revenues. The Company did not have any
one customer which represented 10% or more of consolidated revenues for the
fiscal years ended June 30, 2001 or 2000.
STOCK-BASED COMPENSATION
The Company accounts for stock option grants to employees using the
intrinsic value method of accounting prescribed by APB Opinion No. 25,
Accounting for Stock Issued to Employees ("APB 25"). Under the Company's stock
incentive plans, the price of the stock on the grant date is the same as the
amount an employee must pay to exercise the option to acquire the stock;
accordingly, the options have no intrinsic value at grant date, and in
accordance with the provisions of APB 25, no compensation cost is recognized.
Statement of Financial Accounting Standards No. 123 ("SFAS 123"),
"Accounting for Stock-Based Compensation," sets forth alternative accounting and
disclosure requirements for stock-based compensation arrangements. Companies may
continue to follow the provisions of APB 25 to measure and recognize employee
stock-based compensation; however, SFAS 123 requires disclosure of pro forma net
income and earnings per share that would have been reported under the fair value
based recognition provisions of SFAS 123. The Company has disclosed in Note 8
the pro forma information required under SFAS 123.
38
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
FOREIGN CURRENCY GAINS AND LOSSES
The local currency is the functional currency for the Company's foreign
operations in Argentina and Canada. The cumulative translation gains and losses,
resulting from translating each foreign subsidiary's financial statements from
the functional currency to U.S. dollars, is included in other comprehensive
income and accumulated in stockholders' equity until a partial or complete sale
or liquidation of the Company's net investment in the foreign entity.
CASH AND CASH EQUIVALENTS
The Company considers all unrestricted highly liquid investments with less
than a three-month maturity when purchased, as cash equivalents.
RECLASSIFICATIONS
Certain reclassifications have been made to the consolidated financial
statements for the years ended June 30, 2001 and 2000 to conform to the year end
June 30, 2002 presentation. The reclassifications consist primarily of
reclassifying certain items from general and administrative expense to direct
expenses.
2. BUSINESS AND PROPERTY ACQUISITIONS
During fiscal 2002 and 2001, the Company completed several small
acquisitions for a total consideration of $44,378,000 and $11,965,000,
respectively, which consisted of a combination of cash, notes and shares of the
Company's common stock. None of the acquisitions completed in fiscal 2002 were
individually material, thus the pro forma effect of these acquisitions is not
required to be presented. Each of the acquisitions was accounted for using the
purchase method and the results of the operations generated from the acquired
assets are included in the Company's results of operations as of the completion
date of each acquisition. There were no acquisitions completed by the Company in
fiscal 2000.
3. COMMITMENTS AND CONTINGENCIES
Various suits and claims arising in the ordinary course of business are
pending against the Company. Management does not believe that the disposition of
any of these items will result in a material adverse impact to the consolidated
financial position, results of operations or cash flows of the Company.
In order to retain qualified senior management, the Company enters into
employment agreements with its executive officers. These employment agreements
run for periods ranging from three to five years, but can be automatically
extended on a yearly basis unless terminated by the Company or the executive
officer. In addition to providing a base salary for each executive officer, the
employment agreements provide for severance payments for each executive equal to
three years of the executive officer's base salary. At June 30, 2002 the annual
base salaries for the executive officers covered under such employment
agreements totaled $1,165,000. The Company also enters into employment
agreements with other key employees as it deems necessary in order to retain
qualified personnel.
39
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
4. LONG-TERM DEBT
The components of the Company's long-term debt are as follows:
JUNE 30,
-------------------
2002 2001
-------- --------
(THOUSANDS)
Senior Credit Facility Revolving Loans (i).............. $ -- $ 2,000
8 3/8% Senior Notes Due 2008 (ii)....................... 276,433 175,000
14% Senior Subordinated Notes Due 2009 (iii)............ 94,257 134,466
5% Convertible Subordinated Notes Due 2004 (iv)......... 49,951 158,426
Capital Leases.......................................... 22,829 22,964
Other notes payable..................................... 140 1,051
-------- --------
443,610 493,907
Less current portion.................................... 7,674 7,946
-------- --------
Total long-term debt.................................... $435,936 $485,961
======== ========
(I) SENIOR CREDIT FACILITY
During the fiscal 2002, the Company's senior credit facility (the "Prior
Senior Credit Facility") consisted of a $100 million revolving credit facility.
In addition, up to $30 million of letters of credit could be issued under the
Prior Senior Credit Facility, but any outstanding letters of credit reduced
borrowing availability under the revolver. The Company drew down approximately
$43 million on January 14, 2002 in order to redeem the 14% Senior Subordinated
Notes. The funds were repaid with the issuance of additional 8 3/8% Notes in
March 2002.
The revolving loans bore interest at rates based upon, at the Company's
option, either the prime rate plus a variable margin of 0.75% to 2.00% or a
Eurodollar rate plus a variable margin of 2.25% to 3.50%. The Company paid
commitment fees on the unused portion of the revolving loan at a varying rate
(depending upon the pricing ratio) of between 0.25% and 0.50%.
During fiscal 2001, a portion of the net proceeds from the 2000 Equity
Offering (see Note 8) was used to repay the entire outstanding balance of the
Tranche A term loan then outstanding under the Prior Senior Credit Facility and
$2.3 million of the Tranche B term loan then outstanding under the Prior Senior
Credit Facility. In addition, $65 million of the net proceeds from the 2000
Equity Offering were used to reduce the principal amount outstanding under the
revolver. The remainder of the net proceeds of the 2000 Equity Offering was used
to retire other long-term debt. A portion of the proceeds from the Company's
8 3/8% Senior Note offering in fiscal 2001 was used to repay the entire
outstanding balance of the Tranche B term loan then outstanding under the Prior
Senior Credit Facility and approximately $59.1 million under the revolver.
At June 30, 2002, there was no balance outstanding under the revolving
loans. Additionally, the Company had outstanding letters of credit of
$27,963,000 and $11,995,000 as of June 30, 2002 and 2001, respectively, under
the senior credit facility related to its workers compensation insurance.
40
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
4. LONG-TERM DEBT (CONTINUED)
(II) 8 3/8% SENIOR NOTES
On March 6, 2001, the Company completed a private placement of $175,000,000
of 8 3/8% Senior Notes due 2008 (the "8 3/8% Senior Notes"). The net cash
proceeds from the private placement were used to repay all of the remaining
balance of the original term loans under the Senior Credit Facility, and a
portion of the revolving loan facility under the Senior Credit Facility then
outstanding. On March 1, 2002, the Company completed a public offering of an
additional $100,000,000 of 8 3/8% Senior Notes due 2008. The net cash proceeds
from the public offering were used to repay all of the remaining balance of the
revolving loan facility under the Senior Credit Facility. The 8 3/8% Senior
Notes are senior unsecured obligations. The 8 3/8% Senior Notes are effectively
subordinated to Key's secured indebtedness which includes borrowings under the
Senior Credit Facility.
On and after March 1, 2005, the Company may redeem some or all of the 8 3/8%
Senior Notes at any time at varying redemption prices in excess of par, plus
accrued interest. In addition, before March 1, 2004, the Company may redeem up
to 35% of the aggregate principal amount of the 8 3/8% Senior Notes with the
proceeds of certain sales of equity at 108.375% of par plus accrued interest.
At June 30, 2002, $275,000,000 principal amount of the 8 3/8% Senior Notes
remained outstanding. The 8 3/8% Senior Notes require semi-annual interest
payments on March 1 and September 1 of each year. Interest payments of
approximately $7,125,000 and $7,328,000 were paid on September 1, 2001 and
March 1, 2002, respectively.
(III) 14% SENIOR SUBORDINATED NOTES
On January 22, 1999, the Company completed the private placement of 150,000
units (the "Units") consisting of $150,000,000 of 14% Senior Subordinated Notes
due 2009 (the "14% Senior Subordinated Notes") and 150,000 warrants to purchase
2,173,433 shares of the Company's Common Stock at an exercise price of $4.88125
per share (the "Unit Warrants"). The net cash proceeds from the private
placement were used to repay substantially all of the remaining $148,600,000
principal amount (plus accrued interest) owed under the Company's bridge loan
facility arranged in connection with the acquisition of Dawson Production
Services, Inc. ("Dawson").
On and after January 15, 2004, the Company may redeem some or all of the 14%
Senior Subordinated Notes at any time at varying redemption prices in excess of
par, plus accrued interest. In addition, before January 15, 2002, the Company
was allowed to redeem up to 35% of the aggregate principal amount of the 14%
Senior Subordinated Notes at 114% of par plus accrued interest with the proceeds
of certain sales of equity. During fiscal 2001, the Company exercised its right
of redemption for $10,313,000 principal amount of the 14% Senior Subordinated
Notes at a price of 114% of the principal amount plus accrued interest. This
transaction resulted in an extraordinary loss before taxes of approximately
$2,561,000. On January 14, 2002 the Company exercised its right of redemption
for $35,403,000 principal amount of the 14% Senior Subordinated Notes at a price
of 114% of the principal amount plus accrued interest. This transaction resulted
in an extraordinary loss before taxes of approximately $8,468,000. Also, during
fiscal 2002, the Company purchased and canceled $6,784,000 principal amount of
the 14% Senior Subordinated Notes at a price of 116% of the principal amount
plus accrued interest. These transactions resulted in extraordinary losses
before taxes of approximately $1,821,000.
41
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
4. LONG-TERM DEBT (CONTINUED)
The Unit Warrants have separated from the 14% Senior Subordinated Notes and
became exercisable on January 25, 2000. On the date of issuance, the value of
the Unit Warrants was estimated at $7,434,000 and is classified as a discount to
the 14% Senior Subordinated Notes on the Company's consolidated balance sheet.
The discount is being amortized to interest expense over the term of the 14%
Senior Subordinated Notes. The 14% Senior Subordinated Notes mature and the Unit
Warrants expire on January 15, 2009. The 14% Senior Subordinated Notes are
subordinate to the Company's senior indebtedness, which includes borrowings
under the Senior Credit Facility and the 8 3/8% Senior Notes.
At June 30, 2002, $97,500,000 principal amount of the 14% Senior
Subordinated Notes remained outstanding. The 14% Senior Subordinated Notes pay
interest semi-annually on January 15 and July 15 of each year. Interest payments
of approximately $9,778,000 and $6,825,000 were made on July 15, 2001 and
January 15, 2002, respectively. As of June 30, 2002, 63,500 Unit Warrants had
been exercised, producing approximately $4,173,000 of proceeds to the Company
and leaving 86,500 Unit Warrants outstanding.
(IV) 5% CONVERTIBLE SUBORDINATED NOTES
In late September and early October 1997, the Company completed a private
placement of $216,000,000 of 5% Convertible Subordinated Notes due 2004 (the "5%
Convertible Subordinated Notes"). The 5% Convertible Subordinated Notes are
subordinate to the Company's senior indebtedness which includes borrowings under
the Senior Credit Facility, the 14% Senior Subordinated Notes and the 8 3/8%
Senior Notes. The 5% Convertible Subordinated Notes are convertible, at the
holder's option, into shares of the Company's common stock at a conversion price
of $38.50 per share, subject to certain adjustments. The 5% Convertible
Subordinated Notes are redeemable, at the Company's option, on and after
September 15, 2000, in whole or part, together with accrued and unpaid interest.
The initial redemption price is 102.86% for the year beginning September 15,
2000 and declines ratably thereafter on an annual basis.
During fiscal 2001, the Company repurchased (and canceled) $47,384,000
principal amount of the 5% Convertible Subordinated Notes. These repurchases
resulted in extraordinary gains before taxes of approximately $4,564,000. During
fiscal 2002, the Company repurchased (and canceled) $108,475,000 principal
amount of the 5% Convertible Subordinated Notes, leaving $49,951,000 principal
amount of the 5% Convertible Subordinated Notes outstanding at June 30, 2002.
These repurchases resulted in extraordinary gains before taxes of approximately
$5,633,000. Interest on the 5% Convertible Subordinated Notes is payable on
March 15 and September 15 of each year. Interest of approximately $3,027,000 and
$1,259,000 was paid on September 15, 2001 and March 15, 2002, respectively.
CAPITALIZED DEBT ISSUANCE COSTS, REPAYMENT SCHEDULE AND INTEREST EXPENSE
The Company capitalized a total of approximately $1,877,000 and $4,958,000
in fees and costs in connection with its various financings during fiscal 2002
and 2001, respectively. The Company did not incur any fees or costs in
connection with financing activities in fiscal 2000.
42
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
4. LONG-TERM DEBT (CONTINUED)
Presented below is a schedule of the repayment requirements of long-term
debt (excluding the discount on the 14% Senior Subordinated Notes and the
premium on the 8 3/8% Senior Notes) for each of the next five years and
thereafter as of June 30, 2002:
PRINCIPAL
FISCAL YEAR ENDING JUNE 30, AMOUNT
--------------------------- -----------
(THOUSANDS)
2003........................................................ $ 7,674
2004........................................................ 7,679
2005........................................................ 57,567
2006........................................................ --
2007........................................................ --
Thereafter.................................................. 372,500
--------
$445,420
========
The Company's interest expense for the years ended June 30, 2002, 2001, and
2000 consisted of the following:
2002 2001 2000
-------- -------- --------
(THOUSANDS)
Cash payments for interest....................... $42,085 $51,524 $61,956
Commitment and agency fees paid 1,183 1,203 1,139
Accretion of discount and premium on notes....... 424 739 743
Amortization of debt issuance costs.............. 2,581 3,578 5,176
Net change in accrued interest................... (1,275) 146 2,916
Capitalized interest............................. (1,666) (630) --
------- ------- -------
$43,332 $56,560 $71,930
======= ======= =======
5. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at June 30, 2002 and 2001. FASB Statement
No. 107, "Disclosures about Fair Value
43
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
5. FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED)
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.
2002 2001
------------------- -------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- -------- -------- --------
Financial Assets:
Cash and cash equivalents................. $ 54,147 $ 54,147 $ 2,098 $ 2,098
Accounts receivable, net.................. 117,907 117,907 177,016 177,016
Notes receivable--related parties......... 274 274 6,050 6,600
Commodity option contracts................ 246 246 1,035 1,035
Financial Liabilities:
Accounts payable.......................... 24,625 24,625 42,544 42,544
Commodity option contracts................ -- -- 344 344
Long-term debt:
Senior Credit Facility.................. -- -- 2,000 2,000
8 3/8% Senior Notes..................... 276,433 287,491 175,000 176,094
14% Senior Subordinated Notes........... 94,257 109,338 134,466 153,498
5% Convertible Subordinated Notes....... 49,951 46,942 158,426 141,989
Capital lease liabilities............... 22,829 22,829 22,964 22,964
Other debt.............................. 140 140 1,051 1,051
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments:
Cash, trade receivables and trade payables: The carrying amounts approximate
fair value because of the short maturity of those instruments.
Commodity option contracts: under SFAS 133, the carrying amount of the
commodity option contracts approximate fair value. The fair value of the
commodity option contracts is estimated using the discounted forward prices of
each option's index price, for the term of each option contract.
Notes receivable-related parties: The amounts reported relate to notes
receivable from officers of the Company.
Long-term debt: The fair value of the Company's long-term debt is based upon
the quoted market prices for the various notes and debentures at June 30, 2002
and 2001, and the carrying amounts outstanding under the Company's senior credit
facility.
6. DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instruments to manage well defined
commodity price risks. The Company is exposed to credit losses in the event of
nonperformance by the counter-parties to its commodity hedges. The Company only
deals with reputable financial institutions as counter-parties and anticipates
that such counter-parties will be able to fully satisfy their obligations under
the contracts. The Company does not obtain collateral or other security to
support financial instruments subject to credit risk but monitors the credit
standing of the counter-parties.
44
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
6. DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED)
The Company periodically hedges a portion of its oil and natural gas
production through collar and option agreements. The purpose of the hedges is to
provide a measure of stability in the volatile environment of oil and natural
gas prices and to manage exposure to commodity price risk under existing sales
commitments. The Company's risk management objective is to lock in a range of
pricing for expected production volumes. This allows the Company to forecast
future earnings within a predictable range. The Company meets this objective by
entering into collar and option arrangements which allow for acceptable cap and
floor prices.
The Company does not enter into derivative instruments for any purpose other
than for economic hedging. The Company does not speculate using derivative
instruments. The Company has identified the following derivative instruments:
FREESTANDING DERIVATIVES. On March 30, 2000 the Company entered into a
collar arrangement for a 22-month period whereby the Company will pay if the
specified price is above the cap index and the counter-party will pay if the
price should fall below the floor index. The hedge defines a range of cash flows
bounded by the cap and floor prices. On May 25, 2001 the Company entered into an
option arrangement for a 12-month period beginning March 2002 whereby the
counter-party will pay if the price should fall below the floor index. On
May 2, 2002 the Company entered into an option arrangement for a 12-month period
beginning March 2003 whereby the counter-party will pay if the price should fall
below the floor index. The Company desires a measure of stability to ensure that
cash flows do not fall below a certain level.
Prior to the adoption of SFAS 133 as discussed in Note 1, these collars and
options were accounted for as cash flow type hedges. Accordingly, the transition
adjustment resulted in recording a $778,000 liability for the fair value of the
collars to accumulated other comprehensive income, of which $258,000 and
$520,000 was recognized in earnings during fiscal 2002 and 2001, respectively.
While this arrangement was intended to be an economic hedge, as of July 1, 2000,
the Company had not documented the March 30, 2000 oil and natural gas collars as
cash flow hedges and therefore reported a charge to operations of $565,000 for
the increase in fair value of the liability as of September 30, 2000 in other
income. As of October 1, 2000, the Company documented these collars as cash flow
hedges. As of May 25, 2001, the Company had not documented the May 25, 2001 oil
and natural gas options as cash flow hedges and therefore has included income of
$768,000 for the increase in fair value of the asset as of June 30, 2001 in
other income. As of July 1, 2001, the Company documented these options as cash
flow hedges. As of May 2, 2002, the Company had documented the May 2, 2002 oil
and natural gas options as cash flow hedges. The Company recorded a net decrease
in derivative assets net of derivative liabilities of $543,000 and a net
increase of $999,000 during fiscal 2002 and 2001, respectively.
The Company recorded in earnings an ineffectiveness expense of $85,000 and
ineffectiveness income $132,000 for fiscal 2002 and 2001, respectively.
EMBEDDED DERIVATIVES. The Company is party to a volumetric production
payment that meets the definition of an embedded derivative under SFAS 133.
Effective July 1, 2000, the Company determined and documented that the
volumetric production payment is excluded from the scope of SFAS 133 under the
normal purchases/sales exclusion as set forth in SFAS 138.
45
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
6. DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED)
For fiscal 2000, gains and amortization of premiums paid on option contracts
are recognized as an adjustment to sales revenue when the related transactions
being hedged are finalized. The net effect of the Company's commodity hedging
activities decreased oil and natural gas revenues for the year ended June 30,
2000 by $822,270.
The following table sets forth the future volumes hedged by year and the
weighted-average strike price of the option contracts at June 30, 2002 and 2001:
MONTHLY INCOME STRIKE PRICE
------------------- PER BBL/MMBTU
OIL GAS -------------------
(BBLS) (MMBTU) TERM FLOOR CAP FAIR VALUE
-------- -------- ----------------- -------- -------- ----------
At June 30, 2002
Oil Put............ 5,000 -- Mar 2002-Feb 2003 $22.00 -- $ 24,000
Oil Put............ 4,000 -- Mar 2003-Feb 2004 $21.00 -- $ 118,000
Gas Put............ -- 75,000 Mar 2002-Feb 2003 $ 3.00 -- $ 104,000
At June 30, 2001
Oil Collar......... 5,000 -- Mar 2001-Feb 2002 $19.70 $23.70 $ (115,000)
Oil Put............ 5,000 -- Mar 2002-Feb 2003 $22.00 -- $ 141,000
Gas Collar......... -- 40,000 Mar 2001-Feb 2002 $ 2.40 $ 2.91 $ (229,000)
Gas Put............ -- 75,000 Mar 2002-Feb 2003 $ 3.00 -- $ 894,000
(The strike prices for the oil collars and puts are based on the NYMEX spot
price for West Texas Intermediate; the strike prices for the natural gas collars
are based on the Inside FERC-West Texas Waha spot price; the strike price for
the natural gas put is based on the Inside FERC-El Paso Permian spot price.)
7. OTHER ACCRUED LIABILITIES
Other accrued liabilities consist of the following:
JUNE 30,
-------------------
2002 2001
-------- --------
(THOUSANDS)
Accrued payroll, taxes and employee benefits.............. $28,479 $31,242
State sales, use and other taxes.......................... 2,344 5,825
Oil and natural gas revenue distribution.................. 1,271 1,606
Other..................................................... 17,371 10,250
------- -------
Total..................................................... $49,465 $48,923
======= =======
Other non-current accrued expenses consist primarily of workers compensation
reserves.
46
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
8. STOCKHOLDERS' EQUITY
EQUITY OFFERINGS
On December 19, 2001, the Company closed a public offering of 5,400,000
shares of common stock, yielding approximately $43.2 million, or $8.00 per
share, to the Company, (the "Equity Offering"). Net proceeds from the Equity
Offering of approximately $42.6 million were used to temporarily reduce amounts
outstanding under the Company's revolving line of credit. The net proceeds of
the Equity Offering were ultimately used in January 2002 to redeem a portion of
the Company's 14% Senior Subordinated Notes fully utilizing the Company's equity
"claw-back" rights for up to 35% of the original $150 million issued.
On June 30, 2000, the Company closed a public offering of 11,000,000 shares
of common stock at $9.625 per share, or approximately $106 million (the "2000
Equity Offering"). Net proceeds from the 2000 Equity Offering of approximately
$101 million were used to repay a portion of the Company's term loan borrowings
and revolving line of credit under its senior credit facility and retire other
long-term debt.
STOCK INCENTIVE PLANS
On January 13, 1998 the Company's shareholders approved the Key Energy
Group, Inc. 1997 Incentive Plan, as amended (the "1997 Incentive Plan"). The
1997 Incentive Plan is an amendment and restatement of the plans formerly known
as the "Key Energy Group, Inc. 1995 Stock Option Plan" (the "1995 Option Plan")
and the "Key Energy Group, Inc. 1995 Outside Directors Stock Option Plan" (the
"1995 Directors Plan") (collectively, the "Prior Plans").
All options previously granted under the Prior Plans and outstanding as of
November 17, 1997 (the date on which the Company's board of directors adopted
the plan) were assumed and continued, without modification, under the 1997
Incentive Plan.
Under the 1997 Incentive Plan, the Company may grant the following awards to
key employees, directors who are not employees ("Outside Directors") and
consultants of the Company, its controlled subsidiaries, and its parent
corporation, if any: (i) incentive stock options ("ISOs") as defined in
Section 422 of the Internal Revenue Code of 1986, as amended (the "Code"), (ii)
"nonstatutory" stock options ("NSOs"), (iii) stock appreciation rights ("SARs"),
(iv) shares of the restricted stock, (v) performance shares and performance
units, (vi) other stock-based awards and (vii) supplemental tax bonuses
(collectively, "Incentive Awards"). ISOs and NSOs are sometimes referred to
collectively herein as "Options".
The Company may grant Incentive Awards covering an aggregate of the greater
of (i) 3,000,000 shares of the Company's common stock and (ii) 10% of the shares
of the Company's common stock issued and outstanding on the last day of each
calendar quarter, provided, however, that a decrease in the number of issued and
outstanding shares of the Company's common stock from the previous calendar
quarter shall not result in a decrease in the number of shares available for
issuance under the 1997 Incentive Plan. As a result of the Company's equity
offerings discussed above, as of June 30, 2002, the number of shares of the
Company's common stock that may be covered by Incentive Awards has increased to
approximately 11.0 million.
Any shares of the Company's common stock that are issued and are forfeited
or are subject to Incentive Awards under the 1997 Incentive Plan that expire or
terminate for any reason will remain
47
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
8. STOCKHOLDERS' EQUITY (CONTINUED)
available for issuance with respect to the granting of Incentive Awards during
the term of the 1997 Incentive Plan, except as may otherwise be provided by
applicable law. Shares of the Company's common stock issued under the 1997
Incentive Plan may be either newly issued or treasury shares, including shares
of the Company's common stock that the Company receives in connection with the
exercise of an Incentive Award. The number and kind of securities that may be
issued under the 1997 Incentive Plan and pursuant to then outstanding Incentive
Awards are subject to adjustments to prevent enlargement or dilution of rights
resulting from stock dividends, stock splits, recapitalizations, reorganization
or similar transactions.
The maximum number of shares of the Company's common stock subject to
Incentive Awards that may be granted or that may vest, as applicable, to any one
Covered Employee (defined below) during any calendar year shall be 500,000
shares, subject to adjustment under the provisions of the 1997 Incentive Plan.
The maximum aggregate cash payout subject to Incentive Awards (including
SARs, performance units and performance shares payable in cash, or other
stock-based awards payable in cash) that may be granted to any one Covered
Employee during any calendar year is $2,500,000. For purposes of the 1997
Incentive Plan, "Covered Employees" means a named executive officer who is one
of the group covered employees as defined in Section 162(m) of the Code and the
regulation promulgated thereunder (i.e., generally the chief executive officer
and the other four most highly compensated executive officers for a given year.)
The 1997 Incentive Plan is administrated by the Compensation Committee
appointed by the Board of Directors (the "Committee") consisting of not less
than two directors each of whom is (i) an "outside director" under
Section 162(m) of the Code and (ii) a "non-employee director" under Rule 16b-3
of the Securities Exchange Act of 1934. In addition, subject to applicable
shareholder approval requirements, the Company may issue NSOs outside the 1997
Incentive Plan.
The exercise price of options granted under the 1997 Incentive Plan and
outside the 1997 Incentive Plan is at or above the fair market value per share
on the date the options are granted. The exercise of NSOs results in a U. S. tax
deduction to the Company equal to the income tax effect of the difference
between the exercise price and the market price at the exercise date. The
following table summarizes the stock option activity related to the Company's
plans (shares in thousands):
FISCAL YEAR ENDED JUNE 30,
----------------------------------------------------------------
2002 2001 2000
------------------- -------------------- -------------------
WEIGHTED WEIGHTED- WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
-------- -------- -------- --------- -------- --------
Outstanding:
Beginning of fiscal year........ 8,703 $7.49 9,470 $6.37 6,920 $5.55
Granted......................... 1,988 8.16 2,533 8.08 3,688 8.61
Exercised....................... (659) 4.53 (3,107) 4.70 (241) 4.56
Forfeited....................... (24) 4.86 (193) 4.92 (897) 9.80
------ ------ -----
End of fiscal year.............. 10,008 7.80 8,703 7.49 9,470 6.37
====== ====== =====
Exercisable--end of fiscal year... 6,273 5,820 4,370
====== ====== =====
48
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
8. STOCKHOLDERS' EQUITY (CONTINUED)
The following table summarizes information about the stock options
outstanding at June 30, 2002 (shares in thousands):
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------- -------------------------
WEIGHTED
AVERAGE NUMBER OF WEIGHTED NUMBER OF WEIGHTED
REMAINING SHARES AVERAGE SHARES AVERAGE
RANGE OF CONTRACTUAL OUTSTANDING AT EXERCISE OUTSTANDING AT EXERCISE
EXERCISE PRICES LIFE JUNE 30, 2002 PRICE JUNE 30, 2002 PRICE
----------------------------- ----------- -------------- -------- -------------- --------
$3.00 - $7.13................ 5.65 2,052 $ 4.63 1,602 $ 4.82
7.25 - 8.13................ 8.75 1,974 7.86 299 7.71
8.25 - 8.31................ 7.71 2,080 8.25 1,857 8.26
8.35 - 8.50................ 7.25 2,225 8.48 1,229 8.47
8.88 - 13.25................ 6.65 1,677 10.12 1,286 10.39
The Company applies the intrinsic value method of APB 25 in accounting for
its employee stock incentive plans. Accordingly, no compensation expense has
been recognized for any stock options issued under the employee plans. Had
compensation expense for stock options granted to employees been recognized
based on the fair value at the grant dates, using the methodology prescribed by
SFAS 123, the Company's net income (loss) and earnings (loss) per share would
have been reduced to pro forma amounts indicated below:
FISCAL YEAR ENDED JUNE 30,
------------------------------------
2002 2001 2000
---------- ---------- ----------
(THOUSANDS, EXCEPT PER SHARE DATA)
Net income (loss):
As reported................................... $38,146 $62,710 $(18,959)
Pro forma..................................... 26,320 52,338 (25,684)
Basic earnings per share of common stock:
As reported................................... $ 0.36 $ 0.63 $ (0.23)
Pro forma..................................... 0.25 0.53 (0.31)
Diluted earnings per share of common stock:
As reported................................... $ 0.35 $ 0.61 $ (0.23)
Pro forma..................................... 0.24 0.51 (0.31)
SFAS 123 does not apply to options granted prior to January 1, 1995;
therefore, the pro forma effect disclosed above may not be representative of pro
forma amounts in future years.
The total fair value of stock options granted during fiscal 2002, 2001 and
2000 was approximately $7,700,000, $11,217,000 and $19,541,000, respectively.
The fair value of each stock option grant was
49
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
8. STOCKHOLDERS' EQUITY (CONTINUED)
estimated on the date of grant using the Black-Sholes option-pricing model,
based on the following weighted-average assumptions.
FISCAL YEAR OF GRANT
------------------------------
2002 2001 2000
-------- -------- --------
Risk-free interest rate........................... 3.35% 4.30% 6.40%
Expected life of options.......................... 5 years 5 years 5 years
Expected volatility of the Company's stock
price........................................... 50% 59% 67%
Expected dividends................................ none none none
9. INCOME TAXES
Components of income tax expense (benefit) are as follows:
FISCAL YEAR ENDED JUNE 30,
------------------------------
2002 2001 2000
-------- -------- --------
(THOUSANDS)
Federal and State:
Current........................................ $ 914 $ 2,304 $(5,588)
Deferred
U.S............................................ 23,160 34,698 (1,818)
Foreign........................................ -- -- --
------- ------- -------
$24,074 $37,002 $(7,406)
======= ======= =======
The Company made no income tax payments which were not offset by
reimbursement for fiscal 2002, 2001 and 2000. Additionally a deferred tax
benefit of $267,000 and $7,004,000 has been allocated to stockholders' equity in
fiscal 2002 and 2001, respectively, for compensation expense for income tax
purposes in excess of amounts recognized for financial reporting purposes.
Income tax expense (benefit) differs from amounts computed by applying the
statutory federal rate as follows:
FISCAL YEAR ENDED JUNE 30,
------------------------------------
2002 2001 2000
-------- -------- --------
Income tax computed at statutory rate............... 35.0% 35.0% (35.0)%
Amortization of goodwill disallowance............... -- 2.2 7.0
State taxes......................................... 2.8 1.4 --
Change in valuation allowance and other............. (0.9) (1.4) 1.5
---- ---- -----
Change in valuation allowance and other............. 36.9% 37.2% (26.5)%
==== ==== =====
50
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
9. INCOME TAXES (CONTINUED)
Deferred tax assets (liabilities) are comprised of the following:
FISCAL YEAR ENDED
JUNE 30,
---------------------
2002 2001
--------- ---------
(THOUSANDS)
Net operating loss and tax credit carry forwards...... $ 50,089 $ 69,376
Property and equipment................................ (191,834) (183,068)
Self insurance reserves............................... 6,254 405
Allowance for bad debts............................... 1,477 1,542
Other................................................. (2,456) 148
--------- ---------
Net deferred tax liability............................ (136,470) (111,597)
Valuation allowance of deferred tax assets............ (13,520) (15,803)
--------- ---------
Net deferred tax liability, net of valuation
allowance........................................... $(149,990) $(127,400)
========= =========
A valuation allowance is provided when it is more likely than not that some
portion of the deferred tax assets will not be realized. As described below, due
to annual limitations on certain net operating loss carryforwards, it does not
appear more likely than not that the Company will be able to utilize all
available carryforwards prior to their ultimate expiration.
The Company estimates that as of June 30, 2002, the Company will have
available approximately $193,021,646 of net operating loss carryforwards (which
will continue to expire in fiscal 2003). Approximately $51,521,895 of the net
operating loss carryforwards are subject to an annual limitation of
approximately $1,012,000, under Sections 382 and 383 of the Internal Revenue
Code.
10. LEASING ARRANGEMENTS
The Company leases certain property and equipment under non-cancelable
operating leases that generally expire at various dates through fiscal 2007. The
term of the operating leases generally run from 24 to 60 months with varying
payment dates throughout each month.
As of June 30, 2002, the future minimum lease payments under non-cancelable
operating leases are as follows (in thousands):
LEASE
FISCAL YEAR ENDING JUNE 30, PAYMENTS
--------------------------- --------
2003........................................................ $ 6,818
2004........................................................ 6,498
2005........................................................ 6,327
2006........................................................ 4,198
2007........................................................ 1,509
-------
$25,350
=======
Operating lease expense was approximately $6,456,000, $6,072,000, and
$6,460,000 for the fiscal years ended June 30, 2002, 2001 and 2000,
respectively.
51
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
11. EMPLOYEE BENEFIT PLANS
In order to retain quality personnel, the Company maintains 401(k) plans as
part of its employee benefits package. From July 1, 1998 through December 31,
1998, the Company matched 100% of employee contributions into its 401(k) plan up
to a maximum of $1,000 per participant per year. From January 1, 1999 through
March 31, 2000, the Company elected not to match employee contributions.
Commencing April 1, 2000, the Company matches, 100% of employee contributions
into its 401(k) plan up to a maximum of $250 per participant per year. The
maximum limit was increased to $500 effective October 1, 2000, $750 effective
January 1, 2001 and $1,000 effective July 1, 2001. The Company's matching
contributions for fiscal 2002, 2001 and 2000 were approximately $2,123,000,
$1,857,000 and $77,000, respectively.
12. TRANSACTIONS WITH RELATED PARTIES
Effective as of July 1, 2001, the Company entered into an amended and
restated employment agreement with Francis D. John (the "Employment Agreement")
pursuant to which Mr. John serves as the Chairman of the Board, President and
Chief Executive Officer of the Company. The Employment Agreement provided for
the payment of a one-time retention incentive payment. The purpose of this
retention incentive payment was to retire all amounts owed by Mr. John under
incentive-based loans previously made to him (which, because certain performance
criteria had been previously met, the Company was scheduled to forgive ratably
over a ten-year period as long as Mr. John continued to serve the Company in his
present capacity) and in the process provide Mr. John with incentive to remain
with the Company for the next ten years. On December 1, 2001, the incentive
retention payment was paid to Mr. John and was comprised of two components:
(i) approximately $6.5 million in principal and interest accrued through the
date of the payment and (ii) approximately $5.6 million in a tax "gross-up"
payment. The entire payment was withheld by the Company and used to satisfy
Mr. John's tax obligations and his obligations under the loans. Pursuant to the
Employment Agreement, Mr. John will earn the incentive retention payment over a
ten-year period beginning July 1, 2001, with one-tenth of the total bonus being
earned on June 30 of each year, beginning on June 30, 2002. For fiscal 2002,
Mr. John earned approximately $1.3 million of the retention incentive payment.
If Mr. John voluntarily terminates his employment with the Company or if
Mr. John is terminated by the Company for Cause (as defined in the Employment
Agreement), Mr. John will be obligated to repay the entire remaining unearned
balance of the retention incentive payment immediately upon such termination.
However, if Mr. John's employment with the Company is terminated (i) by the
Company other than for Cause, (ii) by Mr. John for Good Reason (as defined in
the Employment Agreement), (iii) as a result of Mr. John's death or Disability
(as defined in the Employment Agreement), or (iv) as a result of a Change in
Control (as defined in the Employment Agreement), the remaining unearned balance
of the retention incentive payment will be treated as earned as of the date of
such event.
13. BUSINESS SEGMENT INFORMATION
The Company's reportable business segments are well servicing and contract
drilling. Oil and natural gas production operations are presented in
"corporate/other."
WELL SERVICING: the Company's operations provide well servicing (ongoing
maintenance of existing oil and natural gas wells), workover (major repairs or
modifications necessary to optimize the level of production from existing oil
and natural gas wells) and production services (fluid hauling and fluid storage
tank rental).
52
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
13. BUSINESS SEGMENT INFORMATION (CONTINUED)
CONTRACT DRILLING: the Company provides contract drilling services for
major and independent oil companies onshore the continental United States,
Argentina and Ontario, Canada.
The Company's management evaluates the performance of its operating segments
based on net income and operating profits (revenues less direct operating
expenses). Corporate expenses include general corporate expenses associated with
managing all reportable operating segments. Corporate assets consist principally
of cash and cash equivalents, deferred debt financing costs and deferred income
tax assets.
WELL CONTRACT CORPORATE/
SERVICING DRILLING OTHER TOTAL
--------- -------- ---------- ----------
TWELVE MONTHS ENDED JUNE 30, 2002
Operating revenues................................. $706,629 $ 87,077 $ 8,858 $ 802,564
Operating profit................................... 216,947 26,516 4,328 247,791
Depreciation, depletion and amortization........... 64,540 9,191 4,534 78,265
Interest expense................................... 1,448 -- 41,884 43,332
Net income (loss) before extraordinary gain
(loss)*.......................................... 76,547 7,630 (42,994) 41,183
Identifiable assets................................ 686,425 91,374 264,127 1,041,926
Capital expenditures (excluding acquisitions)...... 57,857 19,861 15,979 93,697
TWELVE MONTHS ENDED JUNE 30, 2001
Operating revenues................................. $758,273 $107,639 $ 7,350 $ 873,262
Operating profit................................... 257,949 30,273 2,886 291,108
Depreciation, depletion and amortization........... 63,578 7,947 3,622 75,147
Interest expense................................... 1,831 -- 54,729 56,560
Net income (loss) before extraordinary gain (loss)
*................................................ 109,159 9,466 (56,344) 62,281
Identifiable assets................................ 664,611 95,473 278,325 1,038,409
Capital expenditures (excluding acquisitions)...... 51,064 15,884 15,802 82,750
TWELVE MONTHS ENDED JUNE 30, 2000
Operating revenues................................. $559,492 $ 68,428 $ 9,812 $ 637,732
Operating profit................................... 150,769 10,129 5,665 166,563
Depreciation, depletion and amortization........... 62,680 6,105 2,187 70,972
Interest expense................................... 2,300 -- 69,630 71,930
Net income (loss) before extraordinary gain
(loss)*.......................................... 48,062 (1,664) (66,968) (20,570)
Identifiable assets................................ 635,304 89,574 322,754 1,047,632
Capital expenditures (excluding acquisitions)...... 26,469 8,282 3,422 38,173
------------------------
* Net income (loss) before extraordinary gain (loss) for the contract drilling
segment includes a portion of well servicing general and administrative
expenses allocated on a percentage of revenue basis.
Operating revenues and operating profit for the Company's foreign
operations, which includes Argentina and Canada, were $33.2 million and $6.4
million, respectively, for the year ended June 30, 2002. Operating revenues and
operating profit for the Company's foreign operations, which includes Argentina
and Canada, were $54.5 million and $13.4 million, respectively, for the year
ended June 30, 2001.
53
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
13. BUSINESS SEGMENT INFORMATION (CONTINUED)
Operating revenues and operating profit for the Company's foreign operations,
which includes Argentina and Canada, were $37.7 million and $7.3 million,
respectively, for the year ended June 30, 2000.
The Company had $27.9 million and $84.1 million of identifiable assets as of
June 30, 2002 and 2001, respectively, related to its foreign operations.
14. SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
YEAR ENDED JUNE 30,
------------------------------
2002 2001 2000
-------- -------- --------
(THOUSANDS)
Fair value of common stock issued in purchase
transactions.................................... $25,067 $8,120 $ --
Fair value of common stock issued upon conversion
of long-term debt............................... -- 957 3,606
Capital lease obligations......................... 10,047 9,595 10,758
15. UNAUDITED SUPPLEMENTARY INFORMATION--QUARTERLY RESULTS OF OPERATIONS
Summarized quarterly financial data for fiscal 2002, and 2001 are as
follows:
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(THOUSANDS, EXCEPT PER SHARE AMOUNTS)
FISCAL 2002
Revenues.......................................... $249,237 $213,337 $170,241 $169,749
Income from operations............................ 46,138 28,271 1,408 (10,560)
Net income (loss) before extraordinary gain
(loss).......................................... 28,996 17,368 635 (5,816)
Extraordinary gain (loss), net of tax............. 180 2,091 (5,261) (47)
-------- -------- -------- --------
Net income (loss)................................. $ 29,176 $ 19,459 $ (4,626) $ (5,863)
======== ======== ======== ========
Earnings (loss) per share:
Basic--before extraordinary gain (loss)......... $ 0.29 $ 0.17 $ 0.01 $ (0.05)
Extraordinary gain (loss), net of tax........... -- 0.02 (0.05) --
-------- -------- -------- --------
Basic--after extraordinary gain (loss).......... $ 0.29 $ 0.19 $ (0.04) $ (0.05)
======== ======== ======== ========
Diluted--before extraordinary gain (loss)....... $ 0.28 $ 0.17 $ 0.01 $ (0.05)
Extraordinary gain (loss), net of tax........... -- 0.02 (0.05) --
-------- -------- -------- --------
Diluted--after extraordinary gain (loss)........ $ 0.28 $ 0.19 $ (0.04) $ (0.05)
======== ======== ======== ========
Weighted average shares outstanding:
Basic........................................... 101,727 103,115 108,551 109,776
Diluted......................................... 103,829 104,811 110,059 109,776
54
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
15. UNAUDITED SUPPLEMENTARY INFORMATION--QUARTERLY RESULTS OF OPERATIONS
(CONTINUED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(THOUSANDS, EXCEPT PER SHARE AMOUNTS)
FISCAL 2001
Revenues.......................................... $191,679 $203,911 $227,370 $250,302
Income from operations............................ 12,229 18,063 27,912 41,079
Net income before extraordinary gain (loss)....... 7,510 11,094 17,587 26,090
Extraordinary gain (loss), net of tax............. 1,197 68 (167) (669)
-------- -------- -------- --------
Net income........................................ $ 8,707 $ 11,162 $ 17,420 $ 25,421
======== ======== ======== ========
Earnings per share:
Basic--before extraordinary gain (loss)......... $ 0.08 $ 0.11 $ 0.18 $ 0.26
Extraordinary gain (loss), net of tax........... 0.01 -- -- (0.01)
-------- -------- -------- --------
Basic--after extraordinary gain (loss).......... $ 0.09 $ 0.11 $ 0.18 $ 0.25
======== ======== ======== ========
Diluted--before extraordinary gain (loss)....... $ 0.08 $ 0.11 $ 0.17 $ 0.25
Extraordinary gain (loss), net of tax........... 0.01 -- -- (0.01)
-------- -------- -------- --------
Diluted--after extraordinary gain (loss)........ $ 0.09 $ 0.11 $ 0.17 $ 0.24
======== ======== ======== ========
Weighted average shares outstanding:
Basic........................................... 96,880 97,534 98,211 100,179
Diluted......................................... 100,472 100,534 103,524 104,401
16. VOLUMETRIC PRODUCTION PAYMENT
In March 2000, Key sold a portion of its future oil and natural gas
production from Odessa Exploration Incorporated, its wholly owned subsidiary,
for gross proceeds of $20 million pursuant to an agreement under which the
purchaser is entitled to receive a share of the production from certain oil and
natural gas properties in amounts ranging from 3,500 to 10,000 barrels of oil
and 58,800 to 122,100 Mmbtus of natural gas per month over a six year period
ending February 2006. The total volume of the forward sale is approximately
486,000 barrels of oil and 6.135 million Mmbtus of natural gas.
17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The Company's senior notes are guaranteed by all of the Company's operating
subsidiaries (except for its oil and natural gas production subsidiary and its
foreign subsidiaries), all of which are wholly-owned. The guarantees are joint
and several, full, complete and unconditional. There are currently no
restrictions on the ability of the subsidiary guarantors to transfer funds to
the parent company.
The accompanying condensed consolidating financial information has been
prepared and presented pursuant to SEC Regulation S-X Rule 3-10 "Financial
Statements of Guarantors and Issuers of Guaranteed Securities Registered or
Being Registered." The information is not intended to present the financial
position, results of operations and cash flows of the individual companies or
groups of companies in accordance with generally accepted accounting principles.
55
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (CONTINUED)
CONDENSED CONSOLIDATING BALANCE SHEETS
JUNE 30, 2002
---------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------- ------------ ------------
(IN THOUSANDS)
Assets:
Current assets.................. $ 64,814 $ 117,140 $10,119 $ -- $ 192,073
Net property and equipment...... 43,003 748,158 17,739 -- 808,900
Goodwill, net................... 3,374 197,144 551 -- 201,069
Deferred costs, net............. 12,580 -- -- -- 12,580
Intercompany receivables........ 537,416 -- -- (537,416) --
Other assets.................... 21,593 6,780 -- -- 28,373
-------- ---------- ------- --------- ----------
Total assets...................... $682,780 $1,069,222 $28,409 $(537,416) $1,242,995
======== ========== ======= ========= ==========
Liabilities and equity:
Current liabilities............. $ 48,388 $ 45,427 $ 2,813 $ -- $ 96,628
Long-term debt.................. 420,717 -- -- -- 420,717
Capital lease obligations....... 1,457 13,762 -- -- 15,219
Intercompany payables........... -- 516,761 20,655 (537,416) --
Deferred tax liability.......... 149,990 -- -- -- 149,990
Other long-term liabilities..... 13,474 10,101 -- -- 23,575
Stockholders' equity............ 48,754 483,171 4,941 -- 536,866
-------- ---------- ------- --------- ----------
Total liabilities and
stockholders' equity............ $682,780 $1,069,222 $28,409 $(537,416) $1,242,995
======== ========== ======= ========= ==========
56
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (CONTINUED)
JUNE 30, 2001
---------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------- ------------ ------------
(IN THOUSANDS)
Assets:
Current assets.................. $ 10,680 $ 165,653 $29,817 $ -- $ 206,150
Net property and equipment...... 21,418 717,989 54,309 -- 793,716
Goodwill, net................... 3,374 184,379 2,122 -- 189,875
Deferred costs, net............. 17,624 -- -- -- 17,624
Intercompany receivables........ 664,592 -- -- (664,592) --
Other assets.................... 15,303 5,616 -- -- 20,919
-------- ---------- ------- --------- ----------
Total assets...................... $732,991 $1,073,637 $86,248 $(664,592) $1,228,284
======== ========== ======= ========= ==========
Liabilities and equity:
Current liabilities............. $ 35,671 $ 64,679 $15,203 $ -- $ 115,553
Long-term debt.................. 470,578 -- -- -- 470,578
Capital lease obligations....... 90 15,331 (38) -- 15,383
Intercompany payables........... -- 608,764 55,828 (664,592) --
Deferred tax liability.......... 127,400 -- -- -- 127,400
Other long-term liabilities..... 8,240 14,252 -- -- 22,492
Stockholders' equity............ 91,012 370,611 15,255 -- 476,878
-------- ---------- ------- --------- ----------
Total liabilities and
stockholders' equity............ $732,991 $1,073,637 $86,248 $(664,592) $1,228,284
======== ========== ======= ========= ==========
57
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (CONTINUED)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEAR ENDED JUNE 30, 2002
---------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------- ------------ ------------
(IN THOUSANDS)
Revenues........................... $ 1,247 $768,106 $33,211 $ -- $802,564
Costs and expenses:
Direct expenses.................. -- 527,977 26,796 -- 554,773
Depreciation, depletion and
amortization expense........... 1,830 73,252 3,183 -- 78,265
General and administrative
expense........................ 22,715 34,481 2,298 -- 59,494
Interest......................... 41,883 857 592 -- 43,332
Other............................ -- -- 1,443 -- 1,443
-------- -------- ------- ---- --------
Total costs and expenses........... 66,428 636,567 34,312 -- 737,307
-------- -------- ------- ---- --------
Income (loss) before income
taxes............................ (65,181) 131,539 (1,101) -- 65,257
Income tax (expense) benefit....... 24,045 (48,525) 406 -- (24,074)
-------- -------- ------- ---- --------
Net income (loss) before
extraordinary items.............. (41,136) 83,014 (695) -- 41,183
Extraordinary items, net of tax.... (3,037) -- -- -- (3,037)
-------- -------- ------- ---- --------
Net income (loss).................. $(44,173) $ 83,014 $ (695) $ -- $ 38,146
======== ======== ======= ==== ========
YEAR ENDED JUNE 30, 2001
---------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------- ------------ ------------
(IN THOUSANDS)
Revenues........................... $ 2,018 $816,724 $54,520 $ -- $873,262
Costs and expenses:
Direct expenses.................. -- 540,987 41,167 -- 582,154
Depreciation, depletion and
amortization expense........... 1,353 69,714 4,080 -- 75,147
General and administrative
expense........................ 19,158 37,558 3,402 -- 60,118
Interest......................... 54,464 1,275 821 -- 56,560
Other............................ -- -- -- -- --
-------- -------- ------- ---- --------
Total costs and expenses........... 74,975 649,534 49,470 -- 773,979
-------- -------- ------- ---- --------
Income (loss) before income
taxes............................ (72,957) 167,190 5,050 -- 99,283
Income tax (expense) benefit....... 27,190 (62,310) (1,882) -- (37,002)
-------- -------- ------- ---- --------
Net income (loss) before
extraordinary items.............. (45,767) 104,880 3,168 -- 62,281
Extraordinary items, net of tax.... 429 -- -- -- 429
-------- -------- ------- ---- --------
Net income (loss).................. $(45,338) $104,880 $ 3,168 $ -- $ 62,710
======== ======== ======= ==== ========
58
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (CONTINUED)
YEAR ENDED JUNE 30, 2000
---------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------- ------------ ------------
(IN THOUSANDS)
Revenues........................... $ 790 $599,225 $ 37,717 $ -- $637,732
Costs and expenses:
Direct expenses.................. -- 440,741 30,428 -- 471,169
Depreciation, depletion and
amortization expense........... 1,162 66,453 3,357 -- 70,972
General and administrative
expense........................ 10,774 37,704 3,159 -- 51,637
Interest......................... 69,802 1,527 601 -- 71,930
Other............................ -- -- -- -- --
-------- -------- -------- ---- --------
Total costs and expenses........... 81,738 546,425 37,545 -- 665,708
-------- -------- -------- ---- --------
Income (loss) before income
taxes............................ (80,948) 52,800 172 -- (27,976)
Income tax (expense) benefit....... 21,429 (13,977) (46) -- 7,406
-------- -------- -------- ---- --------
Net income (loss) before
extraordinary items.............. (59,519) 38,823 126 -- (20,570)
Extraordinary items, net of tax.... 1,611 -- -- -- 1,611
-------- -------- -------- ---- --------
Net income (loss).................. $(57,908) $ 38,823 $ 126 $ -- $(18,959)
======== ======== ======== ==== ========
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FISCAL YEAR ENDED JUNE 30, 2002
----------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------- ------------ ------------
(IN THOUSANDS)
Net cash provided by (used in)
operating activities............ $ 95,948 $ 78,577 $ 4,191 $ -- $ 178,716
Net cash provided by (used in)
investing activities............ (37,188) (67,092) (4,469) -- (108,749)
Net cash provided by (used in)
financing activities............ (7,665) (9,637) (13) -- (17,315)
Effect of exchange rate changes on
cash............................ -- -- (603) -- (603)
--------- -------- ------- ---- ---------
Net increase (decrease) in cash... 51,095 1,848 (894) -- 52,049
Cash and cash equivalents at
beginning of period............. 1,647 (2,005) 2,456 -- 2,098
--------- -------- ------- ---- ---------
Cash and cash equivalents at end
of period....................... $ 52,742 $ (157) $ 1,562 $ -- $ 54,147
========= ======== ======= ==== =========
59
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION (CONTINUED)
FISCAL YEAR ENDED JUNE 30, 2001
----------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------- ------------ ------------
(IN THOUSANDS)
Net cash provided by (used in)
operating activities............ $ 68,932 $ 64,673 $ 9,742 $ -- $ 143,347
Net cash provided by (used in)
investing activities............ (19,824) (56,976) (7,180) -- (83,980)
Net cash provided by (used in)
financing activities............ (158,627) (8,456) (59) -- (167,142)
--------- -------- ------- ---- ---------
Net increase (decrease) in cash... (109,519) (759) 2,503 -- (107,775)
Cash and cash equivalents at
beginning of period............. 111,166 (1,246) (47) -- 109,873
--------- -------- ------- ---- ---------
Cash and cash equivalents at end
of period....................... $ 1,647 $ (2,005) $ 2,456 $ -- $ 2,098
========= ======== ======= ==== =========
FISCAL YEAR ENDED JUNE 30, 2000
----------------------------------------------------------------------
PARENT GUARANTOR NON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ------------- ------------ ------------
(IN THOUSANDS)
Net cash provided by (used in)
operating activities............ $ 18,962 $ 10,434 $ 5,464 $ -- $ 34,860
Net cash provided by (used in)
investing activities............ (4,468) (26,671) (6,627) -- (37,766)
Net cash provided by (used in)
financing activities............ 80,070 9,287 (56) -- 89,301
--------- -------- ------- ---- ---------
Net increase (decrease) in cash... 94,564 (6,950) (1,219) -- 86,395
Cash and cash equivalents at
beginning of period............. 16,602 5,704 1,172 -- 23,478
--------- -------- ------- ---- ---------
Cash and cash equivalents at end
of period....................... $ 111,166 $ (1,246) $ (47) $ -- $ 109,873
========= ======== ======= ==== =========
18. ARGENTINA FOREIGN CURRENCY TRANSACTION LOSS
The local currency is the functional currency for the Company's foreign
operations in Argentina and Canada. The cumulative translation gains and losses,
resulting from translating each foreign subsidiary's financial statements from
the functional currency to U.S. dollars are included in other comprehensive
income and accumulated in stockholders' equity until a partial or complete sale
or liquidation of the Company's net investment in the foreign entity.
Since 1991, the Argentine peso has been tied to the U.S. dollar at a
conversion ratio of 1:1. However, in December 2001, the Government of Argentina
announced an exchange holiday and, as a result, Argentine pesos could not be
exchanged into other currencies at December 31, 2001. On January 5 and 6,
60
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
18. ARGENTINA FOREIGN CURRENCY TRANSACTION LOSS (CONTINUED)
2002, the Argentine Congress and Senate gave the President of Argentina
emergency powers and the ability to suspend the law that created the fixed
conversion ratio of 1:1. The Government subsequently announced the creation of a
dual currency system in which certain qualifying transactions will be settled at
an expected fixed conversion ratio of 1.4:1 while all other transactions will be
settled using a free floating market conversion ratio. Under existing guidance,
dividends would not receive the fixed conversion ratio. On January 11, 2002, the
exchange holiday was lifted, making it possible again to buy and sell Argentine
pesos. Banks were legally allowed to exchange currencies, but transactions were
limited and generally took place at exchange houses. These transactions were
conducted primarily by individuals as opposed to commercial transactions, and
occurred at free conversion ratios ranging between 1.6:1 and 1.7:1.
Due to the events described above, which resulted in the temporary lack of
exchangeability of the two currencies at December 31, 2001, the Company
translated the assets and liabilities of its Argentine subsidiary at
December 31, 2001 using a conversion ratio of 1.6:1, which management believes
was indicative of the free floating conversion ratio when the currency market
re-opened on January 11, 2002. At June 30, 2002, the Company used a conversion
ratio of 3.9:1 to translate the assets and liabilities of its Argentine
subsidiary. As a result, a foreign currency translation loss of approximately
$48.3 million is included in other comprehensive income, a component of
stockholders' equity, at June 30, 2002. Since the 1:1 conversion ratio was in
existence prior to December 2001, income statement and cash flows information
for the six months ended December 31, 2001 has been translated using the
historical 1:1 conversion ratio. After December 31, 2001, revenues and expenses
are translated using the average exchange rate during the reporting period.
Additionally, the Argentine government has indicated that as part of its
monetary policy changes, it will re-denominate certain consumer loans from U.S.
dollar-denominated to Argentine peso-denominated. As a result, the Company
recorded a foreign currency transaction loss of $1.8 million in the three months
ended December 31, 2001 related to accounts receivable subject to certain U.S.
dollar-denominated contracts held by its Argentine subsidiary which are subject
to re-denomination. These receivables are subject to additional negotiation with
the Company's customers which may result in recovery of a portion of this loss.
In the six months ended June 30, 2002, the Company recovered approximately $0.4
million resulting in a net foreign currency transaction loss of approximately
$1.4 million for fiscal 2002.
19. SUBSEQUENT EVENTS--ACQUISITION OF Q SERVICES, INC. [UNAUDITED]
On July 19, 2002, the Company acquired Q Services, Inc. ("QSI") pursuant to
an Agreement and Plan of Merger dated May 13, 2002, as amended, by and among the
Company, Key Merger Sub, Inc. and QSI. As consideration for the merger, the
Company issued approximately 17.2 million shares of its common stock to QSI
shareholders and assumed approximately $74 million of QSI's indebtedness, net of
working capital. The aggregate value of the purchase price was approximately
$221 million. Prior to the acquisition, QSI was a privately held corporation
conducting field production, pressure pumping and other service operations in
Louisiana, New Mexico, Oklahoma, Texas and the Gulf of Mexico.
20. SUBSEQUENT EVENTS--NEW SENIOR CREDIT FACILITY [UNAUDITED]
On July 15, 2002, the Company entered into a Third Amended and Restated
Credit Agreement (the "New Senior Credit Facility"). The New Senior Credit
Facility consists of a $150,000,000 revolving loan facility with a $40,000,000
sublimit for letters of credit. The loans are secured by most of the tangible
and
61
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2002, 2001 AND 2000
20. SUBSEQUENT EVENTS--NEW SENIOR CREDIT FACILITY [UNAUDITED] (CONTINUED)
intangible assets of the Company. The revolving loan commitment will terminate
on July 15, 2005 and all revolving loans must be paid on or before that date.
The revolving loans bear interest based upon, at the Company's option, the prime
rate plus a variable margin of 0.00% to 0.75% or a Eurodollar rate plus a
variable margin of 1.25% to 2.75%.
The New Senior Credit Facility contains various financial covenants,
including: (i) a maximum consolidated senior leverage ratio of 2.75 to 1.00,
(ii) a minimum consolidated fixed coverage ratio of 1.50 to 1.00, and (iii) a
maximum consolidated total leverage ratio of 3.50 to 1.00. The Company is also
required to maintain a minimum net worth of $436,972,000 plus (i) 50% of
consolidated net income and (ii) 75% of the net cash proceeds from the sale of
equity.
The New Senior Credit Facility subjects the Company to other restrictions,
including restrictions upon the Company's ability to incur additional debt,
liens and guarantee obligations, to merge or consolidate with other persons, to
make acquisitions, to sell assets, to make dividends, purchases of our stock or
subordinated debt, or to make investments, loans and advances or changes to debt
instruments and organizational documents. All obligations under the New Senior
Credit Facility are guaranteed by most of the Company's subsidiaries and are
secured by most of the Company's assets, including the Company's accounts
receivable, inventory and most equipment.
At September 30, 2002 as a result of retiring certain long-term debt of QSI,
there was approximately $62.0 million outstanding under the New Senior Credit
Facility revolver and $28.0 million in outstanding letters of credit.
62
INDEPENDENT AUDITORS' REPORT
To The Board of Directors and Stockholders
Key Energy Services, Inc.
We have audited the accompanying consolidated balance sheets of Key Energy
Services, Inc., and subsidiaries as of June 30, 2002 and 2001, and the related
consolidated statements of operations, comprehensive income, cash flows and
stockholders' equity for each of the years in the three-year period ended June
30, 2002. In connection with our audits of the consolidated financial
statements, we also have audited the financial statement schedule listed in the
Index at Item 15. These consolidated financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Key Energy Services, Inc. and subsidiaries as of June 30, 2002 and 2001, and the
results of their operations and their cash flows for each of the years in the
three-year period ended June 30, 2002, in conformity with accounting principles
generally accepted in the United States of America. Also, in our opinion, the
related financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for goodwill and other intangible assets in
2002. As discussed in Note 6 to the consolidated financial statements, the
Company changed its method of accounting for derivative instruments and hedging
activities in 2001.
KPMG LLP
Dallas, Texas
August 16, 2002
63
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS.
The following table sets forth the names and ages, as of October 28, 2002,
of each of the Company's executive officers and directors and includes their
current positions.
NAME AGE POSITION
---- -------- --------------------------------------------------------
Francis D. John......... 48 Chairman of the Board, President and Chief Executive
Officer
David J. Breazzano...... 46 Director
Kevin P. Collins........ 52 Director
William D. Fertig....... 46 Director
W. Phillip Marcum....... 58 Director
Morton Wolkowitz........ 74 Director
J. Robinson West........ 56 Director
James J. Byerlotzer..... 56 Executive Vice President and Chief Operating Officer
Royce W. Mitchell....... 48 Executive Vice President, Chief Financial Officer and
Chief Accounting Officer
Francis D. John has been the Chief Executive Officer since October 1989. In
addition, Mr. John has been Chairman of the Board since August 1996. He has been
a Director and President since June 1988 and served as the Chief Financial
Officer from October 1989 through July 1997, and served as Chief Operating
Officer from April 1999 through December 2001. Before joining the Company, he
was Executive Vice President of Finance and Manufacturing of Fresenius
U.S.A., Inc. Mr. John previously held operational and financial positions with
Unisys, Mack Trucks and Arthur Andersen. He received a BS from Seton Hall
University and an MBA from Fairleigh Dickinson University.
David J. Breazzano has been a Director since October 1997. Mr. Breazzano is
one of the founding principals at DDJ Capital Management, LLC, an investment
management firm established in 1996. Mr. Breazzano previously served as a Vice
President and Portfolio Manager at Fidelity Investments ("Fidelity") from 1990
to 1996. Prior to joining Fidelity, Mr. Breazzano was President and Chief
Investment Officer of the T. Rowe Price Recovery Fund. He is also a director of
North East Waste Services, Inc. and Samuels Jewelers, Inc. He holds a BA from
Union College and an MBA from Cornell University.
Kevin P. Collins has been a Director since March 1996. Mr. Collins has been
a managing member of the Old Hill Company LLC since 1997. From 1992 to 1997, he
served as a principal of JHP Enterprises, Ltd., and from 1985 to 1992, as Senior
Vice President of DG Investment Bank, Ltd., both of which were engaged in
providing corporate finance and advisory services. Mr. Collins was a director of
WellTech, Inc. ("WellTech") from January 1994 until March 1996 when WellTech was
merged into the Company. Mr. Collins is also a director of The Penn Traffic
Company, Metretek Technologies, Inc. and London Fog Industries, Inc. He holds a
BS and an MBA from the University of Minnesota.
William D. Fertig has been a Director since April 2000. Mr. Fertig is
Co-Chairman and Chief Investment Officer of Context Capital Management, an
investment advisory firm. Mr. Fertig has been a Principal and Senior Managing
Director of McMahan Securities from 1990 to April of 2002. Mr. Fertig previously
served as a Senior Vice President and Manager of Convertibles at Drexel Burnham
Lambert prior to joining McMahan Securities in 1990, and from 1979 to 1989,
served as Vice President and
64
Convertible Securities Sales Manager at Credit Suisse First Boston. He holds a
BS from Allegheny College and an MBA from NYU's Stern Business School.
W. Phillip Marcum has been a Director since March 1996. Mr. Marcum was a
director of WellTech from January 1994 until March 1996 when WellTech was merged
into the Company. From October 1995 until March 1996, Mr. Marcum was the acting
Chairman of the Board of Directors of WellTech. He has been Chairman of the
Board, President and Chief Executive Officer of Metretek Technologies, Inc.,
formerly known as Marcum Natural Gas Services, Inc. ("Metretek Technologies"),
since January 1991 and is a director of TestAmerica, Inc. He holds a BBA from
Texas Tech University.
Morton Wolkowitz has been a Director since December 1989. Mr. Wolkowitz
served as President and Chief Executive Officer of Wolkow Braker Roofing
Corporation, a company that provided a variety of roofing services, from 1958
through 1989. Mr. Wolkowitz has been a private investor since 1989. He holds a
BS from Syracuse University.
J. Robinson West has been a Director since November 2001. Mr. West is the
founder, and has served as Chairman and a director of the Petroleum Finance
Company, Ltd., strategic advisers to international oil and gas companies,
national oil companies, and petroleum ministries, since 1984. Previously,
Mr. West served as U.S. Assistant Secretary of the Interior with responsibility
for offshore oil leasing policy from 1981 through 1983. He was Deputy Assistant
Secretary of Defense for International Economic Affairs from 1976 through 1977
and a member of the White House Staff from 1974 through 1976. He is currently a
member of the Council on Foreign Relations. He holds a BA with advanced standing
from the University of North Carolina at Chapel Hill and a J.D. from Temple
University.
James J. Byerlotzer was elected Executive Vice President and Chief Operating
Officer effective January 2002. Mr. Byerlotzer served as Executive Vice
President of Domestic Well Service and Drilling Operations from July 1999
through December 1999 and Executive Vice President of Domestic Operations from
December 1999 through December 2001. He joined the Company in September 1998 as
Vice President--Permian Basin Operations after the Company's acquisition of
Dawson Production Services, Inc. ("Dawson"). From February 1997 to
September 1998, he served as the Senior Vice President and Chief Operating
Officer of Dawson. From 1981 to 1997, Mr. Byerlotzer was employed by Pride
Petroleum Services, Inc. ("Pride"). Beginning in February 1996, Mr. Byerlotzer
served as the Vice President--Domestic Operations of Pride. Prior to that time,
he served as Vice President--Permian Basin of Pride and in various other
operating positions in Pride's Gulf Coast and California operations.
Mr. Byerlotzer holds a BA from the University of Missouri in St. Louis.
Royce W. Mitchell was elected Executive Vice President, Chief Financial
Officer and Chief Accounting Officer effective January 2002. Before joining the
Company, he was a partner with KPMG LLP from April 1986 through December 2001
specializing in the oil and gas industry. He received a BBA from Texas Tech
University and is a certified public accountant.
Directors are elected at the Company's annual meeting of stockholders and
serve until the next annual meeting of stockholders and until their successors
are elected and qualified. Each executive officer holds office until the first
meeting of the Board of Directors following the annual meeting of stockholders
and until his successor has been duly elected and qualified.
COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires
the Company's directors, executive officers and persons who beneficially own
more than 10% of a registered class of the Company's equity securities, to file
initial reports of ownership on Form 3 and changes in ownership on Forms 4 or 5
with the Securities and Exchange Commission (the "Commission"). Such officers,
directors and 10% stockholders also are required by Commission rules to furnish
the Company with copies of all Section 16(a) reports they file. Based solely on
its review of the copies of such forms furnished to the
65
Company, the Company believes that its directors, executive officers and 10%
stockholders complied with all Section 16(a) filing requirements during the
fiscal year ended June 30, 2002.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE. The following table reflects the compensation
for services to the Company for the years ended June 30, 2002, 2001 and 2000 for
(i) the Chief Executive Officer of the Company, (ii) the other two executive
officers of the Company other than the Chief Executive Officer who were serving
as executive officers at June 30, 2002 and (iii) a former executive officer of
the Company for whom disclosure would have been provided pursuant to
clause (ii) above but for the fact that such individual was not serving as an
executive officer of the company at June 30, 2002, (collectively, the "Named
Executive Officers").
LONG TERM COMPENSATION
AWARDS
ANNUAL -------------------------
COMPENSATION SHARES ALL OTHER
FISCAL -------------------- OTHER ANNUAL UNDERLYING COMPENSATONS
NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($) COMPENSATION($) OPTIONS(1) ($)
--------------------------- -------- --------- -------- --------------- ---------- ------------
Francis D. John ................... 2002 595,000 300,000 105,972(2) 400,000 13,208,568(3)
President and Chief Executive 2001 594,885 845,000 71,116(4) 1,460,000 74,998(5)
Officer 2000 589,519 307,776 -- 2,000,000 --
James J. Byerlotzer ............... 2002 250,000 140,000 -- 150,000 35,865(6)
Executive Vice President and 2001 249,324 275,000 -- 115,000 101,000(7)
Chief Operating Officer 2000 185,000 89,000 -- 300,000 100,250(8)
Royce W. Mitchell ................. 2002 140,692 -- -- 200,000 100,000(9)
Executive Vice President, Chief 2001 -- -- -- -- --
Financial Officer and Chief 2000 -- -- -- -- --
Accounting Officer(10)
Thomas K. Grundman ................ 2002 247,691 150,000 -- 150,000 140,270(11)
Executive Vice President of 2001 274,966 315,000 -- 135,000 78,519(12)
International Operations, Chief 2000 203,845 100,000 -- 500,000 24,975(13)
Financial Officer, and Chief
Accounting Officer(14)
------------------------
(1) Represents the number of shares issuable pursuant to vested and non-vested
stock options granted during the applicable fiscal year.
(2) Represents reimbursement of (i) medical expenses of $24,502,
(ii) professional fees of $44,470, and (iii) other miscellaneous personal
expenses of $25,000. The remaining $12,000 represents the Company's estimate
of the value of Mr. John's use of a company-provided vehicle for personal
business.
(3) As previously reported in the Company's fiscal 2001 Proxy Statement
effective July 1, 2001 and based upon a thorough review and analysis by the
Compensation Committee, the Company determined that it would be in the best
interests of its shareholders to convert the performance-based incentive
loans previously made to Mr. John (which, because the performance criteria
had been met, were scheduled to be forgiven over a ten-year period beginning
July 1, 2001 as long as Mr. John continued to be employed by the Company)
into a ten-year incentive retention payment, the after-tax proceeds of which
would be used to repay all principal and interest on the loans. The majority
of the amount shown in this column represents the a ten-year incentive
retention payment that was made on December 1, 2001 and was comprised of two
components: (i) approximately $7.5 million in principal and interest accrued
through the date of the payment and (ii) approximately $5.6 million in a tax
"gross-up" payment. The entire payment was withheld by the Company and used
to satisfy Mr. John's tax obligations and his obligations under the loans.
Mr. John did not receive any net proceeds from
66
the payment. The a ten-year incentive retention payment is subject to the
same repayment obligations as the prior loan forgiveness schedule, and, as
such, will be earned over the same ten-year period. For fiscal 2002,
Mr. John earned approximately $1.3 million of the retention incentive
payment. See Item 11--Executive Compensation Employment Agreements with
Executive Officers and Item 13--Certain Relationships and Related
Transaction. Also includes $128,996 in premiums paid by the Company for
health insurance and life insurance (cash surrender value the life insurance
policy is $34,774).
(4) Represents reimbursement of (i) medical expenses of $12,186,
(ii) professional fees of $48,930, and (iii) other miscellaneous personal
expenses of $10,000.
(5) Represents premium payments by the Company for life and health insurance.
(6) Represents (i) payments to Mr. Byerlotzer pursuant to a non-competition
agreement entered into in connection with the Company's acquisition of
Dawson Production Services, Inc. of $34,615, and (ii) contributions by the
Company on behalf of Mr. Byerlotzer to the Key Energy Services, Inc. 401(k)
Savings & Retirement Plan of $1,250.
(7) Represents (i) payments to Mr. Byerlotzer pursuant to a non-competition
agreement entered into in connection with the Company's acquisition of
Dawson Production Services, Inc. of $100,000, and (ii) contributions by the
Company on behalf of Mr. Byerlotzer to the Key Energy Services, Inc. 401(k)
Savings & Retirement Plan of $1,000.
(8) Represents (i) payment to Mr. Byerlotzer pursuant to a non-competition
agreement entered into in connection with the Company's acquisition of
Dawson Production Services, Inc. of $100,000 and (ii) contributions by the
Company on behalf of Mr. Byerlotzer to the Key Energy Services, Inc. 401(k)
Savings & Retirement Plan of $250.
(9) Represents a one-time signing bonus that is subject to repayment if
Mr. Mitchell terminates his employment with the Company under certain
circumstances. See Item 11--Executive Compensation--Employment Agreements
with Executive Officers.
(10) Mr. Mitchell joined the Company as an executive officer in January 2002.
(11) Represents (i) forgiveness of relocation loan indebtedness and interest to
Mr. Grundman of $114,295, (ii) premium payments made by the Company for life
insurance of $24,725 and (iii) contributions by the Company on behalf of
Mr. Grundman to the Key Energy Services, Inc. 401(k) Savings & Retirement
Plan of $1,250.
(12) Represents (i) forgiveness of relocation loan indebtedness and interest to
Mr. Grundman of $52,794, (ii) premium payments made by the Company for life
insurance of $24,725 and (iii) contributions by the Company on behalf of
Mr. Grundman to the Key Energy Services, Inc. 401(k) Savings & Retirement
Plan of $1,000.
(13) Represents (i) premium payments by the Company for life insurance of
$24,725 and (ii) contributions by the Company on behalf of Mr. Grundman to
the Key Energy Services, Inc. 401(k) Savings & Retirement Plan of $250.
(14) Mr. Grundman ceased serving as an executive officer as of May 6, 2002.
67
OPTION GRANTS IN LAST FISCAL YEAR
The following table sets forth certain information relating to options
granted under the Key Energy Group, Inc. 1997 Incentive Plan (the "Plan") and
outside the Plan to the Named Executive Officers during fiscal 2002. The Company
did not grant any stock appreciation rights during fiscal 2002.
NUMBER OF INDIVIDUAL GRANTS
SECURITIES OF % OF TOTAL
UNDERLYING OPTIONS GRANTED EXERCISE GRANT
OPTIONS EMPLOYEES IN PRICE PER EXPIRATION PRESENT
NAME GRANTED FISCAL YEAR(1) SHARE DATE VALUE(2)
---- ------------- ----------------- --------- ---------- ----------
Francis D. John..................... 400,000(3) 20.1% $8.00 10/16/11 $1,519,287
Royce W. Mitchell................... 200,000(4) 10.1% $8.90 01/03/12 845,103
James J. Byerlotzer................. 150,000(5) 7.5% $8.00 10/16/11 569,733
Thomas K. Grundman.................. 150,000(5) 7.5% $8.00 10/16/11 569,733
------------------------
(1) Based on options to purchase a total of 1,988,000 shares of Common Stock
granted during fiscal 2002.
(2) The grant date value of stock options was estimated using the Black-Scholes
option pricing model with the following assumptions: expected
volatility--50%; risk-free interest rate--3.35%; time of exercise--5 years;
an dividend yield.
(3) These options were granted on October 16, 2001 and vest as follows: 133,333
on July 1, 2002; 133,333 on July 1, 2003; and 133,334 on July 1, 2004.
(4) These options were granted on January 3, 2002 and vest as follows: 50,000 on
January 3, 2002; 50,000 on January 3, 2003; 50,000 on January 3, 2004; and
50,000 on January 3, 2005.
(5) These options were granted on October 16, 2001 and vest as follows: 50,000
on July 1, 2002; 50,000 on July 1, 2003; and 50,000 on July 1, 2004.
AGGREGATED OPTION EXERCISES AND VALUES AS OF FISCAL YEAR END
The following table sets forth certain information as of June 30, 2002
relating to the number and value of unexercised options held by the Named
Executive Officers. None of the Named Executive Officers exercised Stock Options
during fiscal 2002.
VALUE OF UNEXERCISED
NUMBER OF UNEXERCISED IN-THE MONEY-OPTIONS AT
OPTIONS AT JUNE 30, 2002 JUNE 30, 2002(1)
--------------------------- ---------------------------
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- ------------- ----------- -------------
Francis D. John............................... 2,709,999 900,000 $4,977,707 $1,854,168
Royce W. Mitchell............................. 50,000 150,000 80,000 240,000
James J. Byerlotzer........................... 241,667 418,333 $ 745,004 $1,159,995
Thomas K. Grundman............................ 885,000 0 $2,378,750 $ 0
------------------------
(1) The dollar values in this column are calculated by determining the
difference between the fair market value of the Common Stock for which the
relevant options are exercisable as of the end of the fiscal year and the
exercise price of the options. The fair market value is based on the last
sale price of the Common Stock on the NYSE on June 28, 2002 was $10.50.
EMPLOYMENT AGREEMENTS WITH EXECUTIVE OFFICERS
Effective as of July 1, 2001, the Company entered into an amended and
restated employment agreement with Mr. John, which provides that Mr. John will
serve as Chairman of the Board, President and Chief Executive Officer of the
Company for a five-year term commencing July 1, 2001 and continuing until
June 30, 2006, with an automatic one-year renewal on each June 30, commencing on
June 30, 2006, unless
68
terminated by the Company or by Mr. John with proper notice. Under this
employment agreement, Mr. John's annual base salary is $595,000 per year until
December 31, 2002, and $695,000 per year thereafter, in each case subject to
increase after annual reviews by the Board of Directors. This employment
agreement also provides that Mr. John will be entitled to (i) participate in the
Company's Performance Compensation Plan, with performance criteria to be
approved by the Compensation Committee, (ii) receive additional bonuses at the
discretion of the Compensation Committee, and (iii) participate in stock option
grants made to the Company's executives. In addition to salary and bonus,
Mr. John is entitled to medical, dental, accident and life insurance,
reimbursement of expenses and various other benefits. To the extent Mr. John is
taxed on any such reimbursement or benefit, the Company will pay Mr. John an
amount which, on an after-tax basis, equals the amount of these taxes.
In the event that Mr. John's employment is terminated (1) by the Company
voluntarily or by nonrenewal, (2) by Mr. John for "Good Reason," (3) by either
the Company or Mr. John following a "Change in Control" (in each case as defined
in the employment agreement), or (4) as a result of Mr. John's disability,
Mr. John will be entitled to receive: (i) his accrued but unpaid salary and
bonuses to the date of termination, and a pro rata bonus for the year in which
termination occurs; (ii) a severance payment in an amount equal to three times
his average total annual compensation (i.e., salary plus bonus) for the
preceding three years (except that in the case of termination as a result of
Mr. John's disability, such compensation will be reduced by the amount of any
Company-paid disability insurance proceeds paid to Mr. John); (iii) immediate
vesting and exercisability of all stock options held by him (to the extent not
already vested and exercisable) for the remainder of the original terms of the
options; (iv) any other amounts or benefits earned, accruing or owing to him,
but not yet paid; and (v) continued participation in medical, dental and life
insurance coverage, as well as the receipt of other benefits to which he was
entitled, until the first to occur of the third year anniversary of the date his
employment was terminated or the date on which he receives equivalent coverage
and benefits under the plans and programs of a subsequent employer (or, in the
event of a "Change in Control," an amount in cash equal to the reasonable
expenses that the Company would incur if it were to provide these benefits for
three years). In the event that Mr. John's employment is terminated by the
Company for "Cause," as defined in the employment agreement, or by Mr. John
voluntarily or by nonrenewal, he will be entitled to receive only (i) and
(v) above and will forfeit any restricted stock or options not previously
vested. In the event Mr. John's employment is terminated by reason of his death,
he will be entitled to receive (i), (iii), (iv) and (v) above, except that his
family will be entitled to receive the medical and dental insurance coverage
provided in (v) above until the death of Mr. John's spouse. In addition, if any
of the above benefits are subject to the tax imposed by Section 4999 of the
Internal Revenue Code, the Company will reimburse Mr. John for such tax on an
after-tax basis.
The employment agreement contains a comprehensive non-compete provision that
prohibits Mr. John from engaging in any activities that are competitive with the
Company for a period of three years after the termination of his employment.
Pursuant to the employment agreement, the Company paid to Mr. John, on
December 1, 2001, a one-time retention incentive payment equal to the aggregate
amount of all principal and interest on loans previously made by the Company to
Mr. John that were to be forgiven over a ten year period beginning July 1, 2001,
as well as the amount, on an after-tax basis, required to pay the taxes incurred
Mr. John in connection with such payment. The after-tax proceeds of the payment
were used to repay such loans. The employment agreement provides that if, prior
to June 30, 2011, Mr. John is terminated by the Company for Cause, or by
Mr. John voluntarily or by nonrenewal, Mr. John will repay to the Company a
percentage of the retention incentive bonus beginning at 100% during the first
year and declining at the rate of 10% each year to 0% on and after June 30,
2011.
Effective as of January 1, 2002, Mr. Byerlotzer entered into an employment
agreement with the Company pursuant to which he serves as the Company's
Executive Vice President and Chief Operating Officer. This agreement is for a
two and one-half year term and thereafter for successive one-year terms
69
unless terminated 90 days prior to the commencement of an extension term. Under
the agreement, Mr. Byerlotzer's annual base compensation is $275,000 until
January 1, 2003 at which time it will increase to $325,000. This increase was
implemented effective July 1, 2002. Mr. Byerlotzer's annual salary can be
increased again but not decreased, and Mr. Byerlotzer is eligible for additional
annual incentive bonuses. If during the term of his employment agreement
Mr. Byerlotzer is terminated by the Company for any reason other than for
"Cause", or if he terminates his employment because of a material breach by the
Company or following a change of control of the Company, he will be entitled to
severance compensation equal to his base compensation in effect at the time of
termination payable in equal installments over a 36-month period following
termination; PROVIDED, HOWEVER, that if termination results from a change of
control of the Company, severance compensation will be increased by an amount
equal to three times the average annual bonus received by Mr. Byerlotzer over
the past three years and will be payable in a lump sum on the date of
termination. Also, if Mr. Byerlotzer is subject to the tax imposed by
Section 4999 of the Internal Revenue Code, the Company has agreed to reimburse
him for such tax on an after-tax basis.
Effective as of January 1, 2002, Mr. Mitchell entered into an employment
agreement with the Company pursuant to which he serves as the Company's
Executive Vice President and Chief Financial Officer. This agreement is for a
three-year term and thereafter for successive one-year terms unless terminated
90 days prior to the commencement of an extension term. Under this agreement,
Mr. Mitchell receives an annual base compensation of $295,000, which can be
increased but not decreased, Mr. Mitchell received a one-time signing bonus of
$100,000, and Mr. Mitchell will be eligible for additional annual incentive
bonuses. In the event that, prior to January 1, 2005, Mr. Mitchell is terminated
by the Company for cause, or by Mr. Mitchell voluntarily or by non-renewal,
Mr. Mitchell will repay to the Company a percentage of the bonus beginning at
100% during the first year and declining at the rate of 1/3 each year to 0% on
and after January 1, 2005. If, during the term of his employment agreement,
Mr. Mitchell is terminated by the Company for any reason other than for cause,
or if he terminates his employment because of a material breach by the Company
or following a change of control of the company, he will be entitled to
severance compensation equal to his base compensation in effect at the time of
termination payable in equal installments over a 36-month period following
termination; PROVIDED, HOWEVER, that if termination results from a change of
control of the Company, severance compensation will be increased by an amount
equal to three times the average annual bonus received by Mr. Mitchell over the
past three years and will be payable in a lump sum on the date of termination.
Also, if Mr. Mitchell is subject to the tax imposed by Section 4999 of the
Internal Revenue code, the Company has agreed to reimburse him for such tax on
an after-tax basis.
SEVERANCE AGREEMENT
Effective as of May 6, 2002, the Company entered into a severance
arrangement with Mr. Grundman pursuant to which the Company will make severance
payments to Mr. Grundman totaling $840,000 in equal installments over a
three-year period. In addition, the severance arrangement provides that
Mr. Grundman will be entitled to receive certain group medical and dental, life,
executive life, accident and disability benefits for a three-year period
following his termination, as well as an automobile allowance and certain
additional payments to cover any short-fall in any payments made pursuant to the
Company's medical insurance coverage. Mr. Grundman's severance arrangement with
the Company also provides that all unvested options to acquire shares of Common
Stock that were granted to him became immediately vested and that certain of
those options will remain exercisable for a period of three years.
DIRECTOR COMPENSATION
No director who is also an employee of the Company or any of its
subsidiaries received any fees from the Company for his services as a Director
or as a member of any committee of the Board. During the fiscal year ended
June 30, 2002, all other Directors ("Non-employee Directors") received a fee
equal to $3,000 per month for each month of service and were reimbursed for
travel and other expenses directly associated with Company business.
Additionally, during fiscal 2002, the Company paid the annual
70
premiums on life insurance policies for the benefit of Messrs. Collins and
Marcum in the amount of $2,906 and $5,389, respectively. These policies have
cash surrender values of $7,665 (Marcum) and $6,110 (Collins).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
MANAGEMENT
The following table sets forth as of October 28, 2002, the number of shares
of Common Stock beneficially owned by each (i) each Director, (ii) each
executive officer, and (iii) all Directors and executive officers of the Company
as a group. Except as noted below, each holder has sole voting and investment
power with respect to all shares of Common Stock listed as owned by such person.
PERCENTAGE OF
NUMBER OF OUTSTANDING
NAME OF BENEFICIAL OWNER SHARES(1) SHARES(2)
------------------------ --------- -------------
Francis D. John(3).................................... 2,913,832 2.3%
Kevin P. Collins(4)................................... 292,572 *
William D. Fertig(5).................................. 72,500 *
W. Phillip Marcum(6).................................. 292,572 *
David J. Breazzano(7)................................. 277,500 *
Morton Wolkowitz(8)................................... 807,802 *
J. Robinson West(9)................................... 28,750 *
Royce W. Mitchell(10)................................. 50,000 *
James J. Byerlotzer (11).............................. 389,946 *
Directors and Executive Officers as a group
(9 persons)......................................... 5,125,474 4.0%
------------------------
* Less than 1%
(1) Includes all shares with respect to which each Director or executive
officer directly or indirectly, through any contract, arrangement,
understanding, relationship or otherwise, has or shares the power to vote
or to direct voting of such shares and/or to dispose or to direct the
disposition of such shares. Includes shares that may be purchased under
currently exercisable stock options and warrants.
(2) Based on 128,109,917 shares of Common stock outstanding at October 25,
2002, plus, for each beneficial owner, those number of shares underlying
currently exercisable options held by each executive officer or Director.
(3) Includes 2,843,332 shares issuable upon exercise of vested options. Does
not include 766,668 shares issuable pursuant to options that have not
vested.
(4) Includes 287,500 shares issuable upon the exercise of vested options. Does
not include 22,500 shares issuable pursuant to options that have not
vested.
(5) Includes 67,500 shares issuable upon the exercise of vested options. Does
not include 22,500 shares issuable pursuant to options that have not
vested.
(6) Includes 287,500 shares issuable upon the exercise of vested options. Does
not include 22,500 shares issuable pursuant to options that have not
vested.
(7) Includes 217,500 shares issuable upon the exercise of vested options. Does
not include 22,500 shares issuable pursuant to options that have not
vested.
(8) Includes 224,500 shares issuable upon the exercise of vested options. Does
not include 22,500 shares issuable pursuant to options that have not
vested.
(9) Includes 28,750 shares issuable upon the exercise of vested options. Does
not include 11,250 shares issuable pursuant to options that have not
vested.
(10) Includes 50,000 shares issuable upon the exercise of vested options. Does
not include 150,000 shares issuable pursuant to options that have not
vested.
(11) Includes 371,666 shares issuable upon the exercise of vested options. Does
not include 288,334 shares issuable pursuant to options that have not
vested.
In addition, the following Named Executive Officer who was not an executive
officer of the Company on October 28, 2002, beneficially owns (based on
available information) Common Stock as follows: Thomas K. Grundman--795,000
shares (includes 785,000 shares issuable upon the exercise of vested options).
71
CERTAIN BENEFICIAL OWNERS
The following table sets forth, as of October 28, 2002, certain information
regarding the beneficial ownership of Common Stock by each person, other than
the Company's directors or executive officers, who is known by the Company to
own beneficially more than 5% of the outstanding shares of Common Stock.
SHARES BENEFICIALLY OWNED
AT OCTOBER 19, 2001
--------------------------
NAME AND ADDRESS OF BENEFICIAL OWNER, IDENTITY NUMBER PERCENT
---------------------------------------------- ----------- ---------
Perkins, Wolf, McDonnell & Co.(1) .................... 11,032,564(2) 8.6%
53 W. Jackson Blvd., Suite 722
Chicago, IL 60604
Berger, L.L.C.(3) .................................... 7,650,100(2) 6.0%
210 University Boulevard
Suite 900
Denver, CO 80206
Mellon Financial Corporation(4) ...................... 6,001,311 4.7%
One Mellon Center
Pittsburgh, PA 15258
T. Rowe Price Associates, Inc. ....................... 3,605,400 2.8%
100 E. Pratt Street
Baltimore, MD 21202
------------------------
(1) As reported on Schedule 13G filed with the Commission on February 26, 2002.
(2) The Company believes that Perkins, Wolf, McDonell & Co. shares voting power
with respect to 7,650,100 of its shares with Berger, LLC and that,
therefore, the 7,650,100 shares shown as being beneficially owned by Berger,
LLC are the same securities shown as being beneficially owned by Perkins,
Wolf, McDonnell & Co.
(3) As reported on Schedule 13G filed with the Commission on February 13, 2002.
(4) As reported on Schedule 13G (Amendment No. 1) filed with the Commission on
January 23, 2002.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In connection with the negotiation of the terms of a five-year employment
agreement with 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 loan agreement
with Mr. John dated as of August 2, 1999, which as amended through June 30,
2001, provided that $6.5 million in loans previously made by the Company to
Mr. John, together with the accrued interest payable thereon (accruing at a rate
equal to 125 basis points above LIBOR, adjusted monthly) would be forgiven
ratably during the ten-year period commencing on July 1, 2001 and ending on
June 30, 2011. The loan agreement provided that the foregoing foregiveness of
indebtedness was predicated and conditioned upon Mr. John remaining employed by
the Company during such period. In addition, in the event that Mr. John had been
terminated by the Company for "Cause" (as defined in the agreement), or in the
event that Mr. John had voluntarily terminated his employment with the Company,
the loan agreement further provided that the entire remaining principal balance
of these loans, together with accrued interest payable thereon, would become
immediately due and payable by Mr. John. However, in the event that Mr. John's
employment had been terminated for "Good Reason", or as a result of Mr. John's
death or "Disability", or as a result of a "Change in Control" (all as defined
in that agreement),
72
the loan agreement stipulated that the remaining principal balance outstanding
on the loans, together with accrued interest thereon will be forgiven. This loan
agreement further provided that with respect to any forgiveness of the payment
of principal and interest on the loans, Mr. John would be entitled to receive a
"gross-up" payment in an amount sufficient for him to pay any federal, state, or
local income taxes that may be due and payable by him with respect to the
forgiveness of such indebtedness (principal and interest). The loan agreement
has been effectively superseded by Mr. John's new employment agreement that
provides for a one-time retention incentive payment that was made and used to
repay all amounts owed under the loan agreement (See Item II--Executive
Compensation--Employment Agreements with Executive Officers).
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 and Chief Accounting Officer, the Company made a
$150,000 relocation loan to assist Mr. Grundman's relocation to the Company's
executive offices. Interest on this relocation loan accrued at a rate of 6.125%
per annum. The relocation loan together with accrued interest was forgiven in
three installments of $50,000 (plus accrued interest) on July 1, 2000, $50,000
(plus accrued interest) on July 1, 2001, and $50,000 (plus accured interest) on
May 6, 2002. Mr. Grundman also received or will receive a "gross-up" payment in
an amount sufficient for him to pay any federal, state, or local income taxes
that may be due and payable by him with respect to the forgiveness of such
indebtedness (principal and interest).
In addition, in December 2001, the Company temporarily advanced Mr. John and
Mr. Grundman $201,686 and $24,770, respectively, to satisfy certain medicare tax
obligations incurred by them. Mr. John has repaid his advance in full, and
Mr. Grundman is obligated to repay his advance under the terms of his severance
arrangement.
ITEM 14. DISCLOSURE CONTROLS AND PROCEDURES
(b) Changes in Internal Controls
There were no significant changes in the Company's internal controls during
fiscal 2002 nor did any other factors exist that could significantly affect such
controls through the date of this report.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND REPORTS ON FORM 8-K.
(a) Index to Exhibits
The following documents are filed as part of this report:
(1) See Index to Financial Statements set forth in Item 8.
(2) Financial Statements Schedules:
Key Energy Services, Inc.:
Consolidated Supplementary Financial Statement Schedule As
of and for Each of the Three Years Ended June 30, 2002:
Schedule II--Consolidated Valuation and Qualifying
Accounts.................................................. S-1
The supplemental schedules other than the one listed above are omitted
because of the absence of the conditions under which they are required or
because the required information is included in the Consolidated Financial
Statements or Notes thereto.
73
(3) Exhibits:
3.1 Amended and Restated Articles of Incorporation of the
Company. (Incorporated by reference to the Company's
Registration Statement on Form S-4, Registration
No. 333-369).
3.2 Amended and Restated By-Laws of the Company. (Incorporated
by reference to the Company's Registration Statement on
Form S-4 dated March 8, 1996, Registration No. 333-369).
3.3 Amendment to the Amended and Restated Articles of
Incorporation of the Company. (Incorporated by reference to
Exhibit 3.1 of the Company's Current Report on Form 8-K
dated February 2, 1998, File No. 1-8038).
3.4 Amendment to the Amended and Restated Articles of
Incorporation of the Company. (Incorporated by reference to
Exhibit A of the definitive proxy statement on Schedule 14A
filed by the Company on November 17, 1998, File
No. 1-8038).
3.5 Articles of Amendment to Amended and Restated Articles of
Incorporation of the Company (Incorporated by reference to
Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q
for the quarter ended March 31, 2000, File No. 1-8038).
3.6 Unanimous Consent of the Board of Directors of the Company
dated January 11, 2000, limiting the designation of the
additional authorized shares to common stock (Incorporated
by reference to Exhibit 3.2 of the Company's Quarterly
Report on Form 10-Q for the quarter ended March 31, 2000,
File No. 1-8038).
4.1 Indenture dated as of September 25, 1997, among Key Energy
Group, Inc. and American Stock Transfer and Trust Company.
(Incorporated by reference to Exhibit 10(a) of the Company's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 1997, File No. 1-8038).
4.2 Warrant Agreement dated as of January 22, 1999 between the
Company and The Bank of New York, a New York banking
corporation as warrant agent. (Incorporated by reference to
Exhibit 99(b) of the Company's Form 8-K filed on
February 3, 1999, File No. 1-8038).
4.3 Indenture dated as of January 22, 1999 between the Company
and The Bank of New York as trustee. (Incorporated by
reference to Exhibit 99(c) of the Company's Form 8-K filed
on February 3, 1999, File No. 1-8038).
4.4 Warrant Registration Rights Agreement dated January 22,
1999, by and among the Company and Lehman Brothers Inc.,
Bear, Stearns & Co. Inc., F.A.C./Equities, a division of
First Albany Corporation, and Dain Rauscher Wessels, a
division of Dain Rauscher Incorporated. (Incorporated by
reference to Exhibit 99(e) of the Company's Form 8-K filed
on February 3, 1999, File No. 1-8038).
4.5 Indenture dated March 6, 2001 between the Company and The
Chase Manhattan Bank, a New York banking corporation, as
Trustee (Incorporated by reference to Exhibit 4.1 of the
Company's Form 8-K filed on March 20, 2001, File
No. 1-8038).
10.1 Employment Agreement between the Company and D. Kirk
Edwards, dated as of July 1, 1996. (Incorporated by
reference to Exhibit 10.1 of the Company's Annual Report on
Form 10-K for the year ended June 30, 1997, File
No. 1-8038).
10.2 $550,000,000 Second Amended and Restated Senior Credit
Facility, among Key Energy Group, Inc., PNC Bank, National
Association, Norwest Bank Texas, N.A., PNC Capital
Markets, Inc. and the several lenders from time to time
parties thereto, dated as of June 6, 1997, as amended and
restated through September 14, 1998 (Incorporated by
reference to Exhibit 99.7 of the Company's Current Report on
Form 8-K dated September 28, 1998, File No. 1-8038).
10.3 Amended and Restated Master Guarantee and Collateral
Agreement made by Key Energy Group, Inc. and certain of its
subsidiaries in favor of Norwest Bank Texas, N.A., dated as
of June 6, 1998, as amended and restated through
September 14, 1998 (Incorporated by reference to
Exhibit 99.8 of the Company's Current Report on Form 8-K
dated September 28, 1998, File No. 1-8038).
74
10.4 Intercreditor and Collateral Agency Agreement, dated as of
September 14, 1998. (Incorporated by reference to
Exhibit 99.9 of the Company's Current Report on Form 8-K
dated September 28, 1998, File No. 1-8038).
10.5 Consulting Agreement, dated as of October 7, 1998, by and
among Key Energy Group, Inc. and Michael E. Little.
(Incorporated by reference to Exhibit 10(a) of the Company's
Quarterly Report on Form 10-Q for the quarter ended
December 31, 1998, File No. 1-8038).
10.6 Non-Compete Agreement, dated November 13, 1998, by and
between Key Energy Group, Inc. and James J. Byerlotzer.
(Incorporated by reference to Exhibit 10(c) of the Company's
Quarterly Report on Form 10-Q for the quarter ended
December 31, 1998, File No. 1-8038).
10.7 Non-Compete Agreement, dated October 20, 1998, by and
between Key Energy Group, Inc. and Joseph B. Eustace.
(Incorporated by reference to Exhibit 10(e) of the Company's
Quarterly Report on Form 10-Q for the quarter ended
December 31, 1998, File No. 1-8038).
10.8 Consulting Agreement, dated as of November 12, 1998, by and
among Key Energy Group, Inc. and C. Ron Laidley.
(Incorporated by reference to Exhibit 10(f) of the Company's
Quarterly Report on Form 10-Q for the quarter ended
December 31, 1998, File No. 1-8038).
10.9 Key Energy Group, Inc. Performance Compensation Plan.
(Incorporated by reference to Exhibit 10(g) of the Company's
Quarterly Report on Form 10-Q for the quarter ended
December 31, 1998, File No. 1-8038).
10.10 First Amendment, dated as of December 3, 1997, to the Second
Amended and Restated Senior Credit Facility, dated as of
June 6, 1997, as amended and restated through November 6,
1997. (Incorporated by reference to Exhibit 10(h) of the
Company's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1998, File No. 1-8038).
10.11 Second Amendment, dated as of December 29, 1998, to the
Second Amended and Restated Senior Credit Facility, dated as
of June 6, 1997, as amended and restated through
September 14, 1998, and as amended by the First Amendment
dated as of November 19, 1998. (Incorporated by reference
to Exhibit 10(i) of the Company's Quarterly Report on
Form 10-Q for the quarter ended December 31, 1998, File
No. 1-8038).
10.12 Purchase Agreement dated January 19, 1999 by and among the
Registrant, certain of its subsidiaries, Lehman
Brothers, Inc., Bear, Stearns & Co. Inc., First Albany
Corporation, Dain Rauscher Wessels, a division of Dain
Rauscher Incorporated. (Incorporated by reference to
Exhibit 99(a) of the Company's Form 8-K filed on
February 3, 1999, File No. 1-8038).
10.13 Employment Agreement between the Company and Michael R.
Furrow dated as of January 4, 1999. (Incorporated by
reference to Exhibit 10(g) of the Company's Quarterly Report
on Form 10-Q for the quarter ended December 31, 1998, File
No. 1-8038).
10.14 Third Amendment, dated as of April 8, 1999, to the Second
Amended and Restated Senior Credit Facility, among the
Company, the several lenders from time to time parties
thereto, PNC Bank, National Association, as Administrative
Agent, Norwest Bank Texas, N.A., as Collateral Agent and PNC
Capital Markets, Inc., as Arranger. (Incorporated by
reference to Exhibit 99.5 of the Company's Current Report on
Form 10-K dated April 8, 1999, File No. 1-8038).
10.15 Fourth Amendment, dated as of April 15, 1999, to the Second
Amended and Restated Senior Credit Facility, among the
Company, the several lenders from time to time parties
thereto, PNC Bank, National Association, as Administrative
Agent, Norwest Bank Texas, N.A., as Collateral Agent and PNC
Capital Markets, Inc., as Arranger. (Incorporated by
reference to Exhibit 99.6 of the Company's Current Report on
Form 10-K dated April 8, 1999, File No. 1-8038).
10.16 Fifth Amendment, dated as of May 10, 1999, to the Second
Amended and Restated Senior Credit Facility, among the
Company, the several lenders from time to time parties
thereto, PNC Bank, National Association, as Administrative
Agent, Norwest Bank Texas, N.A., as Collateral Agent, and
PNC Capital Markets, Inc., as Arranger. (Incorporated by
reference to Exhibit 10.91 of the Company's Annual Report on
Form 10-K dated June 30, 1999, File No. 1-8038).
75
10.17 Employment Agreement dated August 5, 1999, between Thomas K.
Grundman and Key Energy Services, Inc. (Incorporated by
reference to Exhibit 10.2 of the Company's Quarterly Report
on Form 10-Q for the quarter ended September 30, 1999, File
No. 1-8038).
10.18 Agreement dated as of August 2, 1999, between Francis D.
John and Key Energy Services, Inc. (Incorporated by
reference to Exhibit 10.5 of the Company's Quarterly Report
on Form 10-Q for the quarter ended September 30, 1999, File
No. 1-8038).
10.19 Promissory Note dated August 3, 1999, made by Thomas K.
Grundman in favor of Key Energy Services, Inc. (Incorporated
by reference to Exhibit 10.6 of the Quarterly Report on
Form 10-Q for the quarter ended September 30, 1999, File
No. 1-8038).
10.20 Demand Note dated August 3, 1999, made by Thomas K. Grundman
in favor of Key Energy Services, Inc. (Incorporated by
reference to Exhibit 10.7 of the Quarterly Report on
Form 10-Q for the quarter ended September 30, 1999, File
No. 1-8038).
10.21 Amendment No. 1 dated as of December 1, 1999, to Agreement
dated as of August 2, 1999, between Francis D. John and Key
Energy Services, Inc. (Incorporated by reference to
Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q
for the quarter ended December 31, 1999, File No. 1-8038).
10.22 Sixth Amendment, dated as of July 14, 1999, to the Second
Amended and Restated Senior Credit Facility, among the
Company, the several lenders from time to time parties
thereto, PNC Bank, National Association, as Administrative
Agent, Norwest Bank Texas, N.A., as Collateral Agent, and
PNC Capital Markets, Inc., as Arranger (Incorporated by
reference to Exhibit 10.1 of the Company's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2000, File
No. 1-8038).
10.23 Seventh Amendment, dated as of March 1, 2000, to the Second
Amended and Restated Senior Credit Facility, among the
Company, the several lenders from time to time parties
thereto, PNC Bank, National Association, as Administrative
Agent, Norwest Bank Texas, N.A., as Collateral Agent, and
PNC Capital Markets, Inc., as Arranger (Incorporated by
reference to Exhibit 10.2 of the Company's Quarterly Report
on Form 10-Q for the quarter ended March 31, 2000, File
No. 1-8038).
10.24 Production and Delivery Agreement dated March 31, 2000,
among Odessa Exploration Incorporated and Norwest Energy
Capital, Inc., (Incorporated by reference to Exhibit 10.3
of the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2000, File No. 1-8038).
10.25 Agreement dated March 31, 2000, among Odessa Exploration
Incorporated, Norwest Energy Capital, Inc. and the Company
(Incorporated by reference to Exhibit 10.4 of the Company's
Quarterly Report on Form 10-Q for the quarter ended
March 31, 2000, File No. 1-8038).
10.26 Underwriting Agreement dated June 27, 2000, among the
Company and Lehman Brothers Inc. for itself and as
Representative of the several underwriters named in Schedule
I thereto (Incorporated by reference to Exhibit 1.1 of the
Company's Current Report on Form 8-K dated June 29, 2000,
File No. 1-8038).
10.27 Amendment No. 2 dated as of June 16, 2000 to Agreement dated
as of August 2, 1999, as amended between Francis D. John and
Key Energy Services, Inc. (Incorporated by reference to
Exhibit 10.83 of the Company's Annual Report on Form 10-K
dated June 20, 2000, File No. 1-8038).
10.28 Amendment dated July 1, 2000 to Employment Agreement dated
August 5, 1999 between Thomas K. Grundman and Key Energy
Services, Inc. (Incorporated by reference to Exhibit 10.1 of
the Company's Quarterly report on Form 10-Q for the quarter
ended September 30, 2000, File No. 1-8038).
10.29 Letter Agreement Amendment dated July 1, 2000 to the Demand
Note dated August 3, 1999 made by Thomas K. Grundman in
favor of Key Energy Services, Inc. (Incorporated by
reference to Exhibit 10.2of the Company's Quarterly Report
of Form 10-Q for the quarter ended September 30, 2000, File
No. 1-8038).
10.30 Purchase Agreement dated March 1, 2001 among the Company,
certain of its subsidiaries, Lehman Brothers, Inc., and Bear
Stearns & Co., Inc. (Incorporated by reference to
Exhibit 1.1 of the Company's Form 8-K filed on March 20,
2001, File No. 1-8038).
76
10.31 Eighth Amendment to the Second Amended and Restated Senior
Credit Facility, dated as of June 6, 1997, as amended and
restated through September 14, 1998 and as further amended,
among Key Energy Group, Inc. (now known as Key Energy
Services, Inc.), the several Lenders from time to time
parties thereto, PNC Bank, National association, as
Administrative Agent, Norwest Bank Texas, N.A., as
Collateral Agent and PNC Capital markets, Inc., as Arranger.
(Incorporated by reference to Exhibit 99.3 of the Company's
Form 8-K filed on March 20, 2001, File No. 1-8038).
10.32 Amendment No. 3 dated as of May 14, 2001 to Agreement dated
as of August 2, 1999, as amended, between Francis D. John
and Key Energy Services, Inc. (Incorporated by reference to
Exhibit 10.49 of the Company's Annual Report on Form 10-K
dated June 30, 2001, File No. 1-8038).
10.33 Second Amended and Restated Employment Agreement dated
October 16, 2001 between Francis D. John and Key Energy
Services, Inc. (Incorporated by reference to Exhibit 10.50
of the Company's Annual Report on Form 10-K/A dated
June 30, 2001, File No. 1-8038).
10.34 Ninth Amendment to the Second Amended and Restated Credit
Agreement, dated as of June 6, 1997, as amended and restated
through September 14, 1998 and as further amended, among Key
Energy Group, Inc. (now known as Key Energy
Services, Inc.), the several Lenders from time to time
parties thereto, PNC Bank, National Association, as
Administrative Agent, Norwest Bank Texas, N.A., as
Collateral Agent and PNC Capital Markets, Inc., as Arranger.
(Incorporated by reference to Exhibit 10.1 of the Company's
Quarterly Report on Form 10-Q dated September 30, 2001, File
1-8038).
10.35 Underwriting Agreement, dated December 13, 2001, between
Registrant and Lehman Brothers Inc. (Incorporated by
reference to Exhibit 1.1 of the Company's Current Report on
Form 8-K dated December 19, 2001, File No. 1-8038).
10.36 Tenth Amendment to the Second Amended and Restated Credit
Agreement, dated as of June 6, 1997, as amended and restated
through September 14, 1998 and as further amended, among Key
Energy Group, Inc. (now known as Key Energy
Services, Inc.), the several Lenders from time to time
parties thereto, PNC Bank, National Association, as
Administrative Agent, Norwest Bank Texas, N.A., as
Collateral Agent and PNC Capital Markets, Inc., as Arranger.
(Incorporated by reference to Exhibit 10.1 of the Company's
Form 8-K filed on December 19, 2001, File 1-8038).
10.37 Employment Agreement between Key Energy Services, Inc. and
Royce W. Mitchell dated December 31, 2001. (Incorporated by
reference to Exhibit 10.3 of the Company's Quarterly Report
on Form 10-Q dated December 31, 2001, File 1-8038).
10.38 Employment Agreement between Key Energy Services, Inc. and
James Byerlotzer dated December 31, 2001. (Incorporated by
reference to Exhibit 10.4 of the Company's Quarterly Report
on Form 10-Q dated December 31, 2001, File 1-8038).
10.39 First Amendment to Second Amended and Restated Employment
Agreement between Francis D. John and Key Energy
Services, Inc. dated December 31, 2001. (Incorporated by
reference to Exhibit 10.5 of the Company's Quarterly Report
on Form 10-Q dated December 31, 2001, File 1-8038).
10.40 Underwriting Agreement, dated February 22, 2002, among the
Registrant and Lehman Brothers Inc., Bear Stearns & Co. Inc.
and First Albany Corporation. (Incorporated by reference to
Exhibit 1.1 of the Company's Current Report on Form 8-K
dated February 27, 2002, File No. 1-8038).
10.41 Eleventh Amendment to the Second Amended and Restated Credit
Agreement, dated as of June 6, 1997, as amended and restated
through September 14, 1998 and as further amended, among Key
Energy Group, Inc. (now known as Key Energy
Services, Inc.), the several Lenders from time to time
parties thereto, PNC Bank, National Association, as
Administrative Agent, Norwest Bank Texas, N.A., as
Collateral Agent and PNC Capital Markets, Inc., as Arranger.
(Incorporated by reference to Exhibit 10.1 of the Company's
Current Report on Form 8-K dated February 27, 2002, File
1-8038).
77
10.42 Twelfth Amendment to the Second Amended and Restated Credit
Agreement, dated as of June 6, 1997, as amended and restated
through September 14, 1998 and as further amended, among Key
Energy Group, Inc. (now known as Key Energy
Services, Inc.), the several Lenders from time to time
parties thereto, PNC Bank, National Association, as
Administrative Agent, Norwest Bank Texas, N.A., as
Collateral Agent and PNC Capital Markets, Inc., as Arranger.
(Incorporated by reference to Exhibit 10.2 of the Company's
Current Report on Form 8-K dated February 27, 2002, File
1-8038).
10.43 Indenture dated as of February 22, 2002 among the Registrant
and U.S. Bank National Association. (Incorporated by
reference to Exhibit 4.1 of the Company's Current Report on
Form 8-K dated February 27, 2002, File 1-8038).
10.44 First Supplemental Indenture dated as of March 1, 2002 among
the Registrant, the Guarantors (as defined therein) and U.S.
Bank National Association. (Incorporated by reference to
Exhibit 4.1 of the Company's Current Report on Form 8-K
dated March 1, 2002, File 1-8038).
10.45 Employment Agreement between Key Energy Services, Inc. and
Thomas K. Grundman dated February 15, 2002. (Incorporated by
reference to Exhibit 10.3 of the Company's Quarterly Report
on Form 10-Q dated March 31, 2002, File 1-8038).
10.46 Separation and Release Agreement between Key Energy
Services, Inc. and Thomas K. Grundman dated May 6, 2002.
10.47 Plan and Agreement of Merger among Key Energy
Services, Inc., Key Merger Sub., Inc. and Q Services, Inc.
dated as of May 13, 2002. (Incorporated by reference to
Exhibit 2.1 of the Company's Current Report on Form 8-K
dated May 17, 2002, File 1-8038).
21 Significant Subsidiaries of the Company.
23 Consent of KPMG LLP.
25.1 Statement of Eligibility of Trustee, U.S. Bank National
Association, a national banking association, on Form T-1.
(Incorporated by reference to Exhibit 25.1 of the Company's
Current Report on Form 8-K dated February 27, 2002, File
1-8038).
99.1 Certification of CEO and CFO Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
*99.2 Certification of CEO and CFO Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
------------------------
* Filed herewith.
(b) Reports on Form 8-K
The Company filed the following reports on Form 8-K during the quarter ended
June 30, 2002:
(i) Current report on Form 8-K dated May 17, 2002 filed to report the
signing of a definitive merger agreement with Q Services, Inc. dated as
of May 13, 2002.
78
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
KEY ENERGY SERVICES, INC.
(Registrant)
Dated: October 28, 2002 By: /s/ FRANCIS D. JOHN
------------------------------------------------
Francis D. John
CHAIRMAN OF THE BOARD, PRESIDENT,
AND CHIEF EXECUTIVE OFFICER
Pursuant to the requirements of the Securities and Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Dated: October 28, 2002 By: /s/ FRANCIS D. JOHN
------------------------------------------------
Francis D. John
CHAIRMAN OF THE BOARD, PRESIDENT,
AND CHIEF EXECUTIVE OFFICER
Dated: October 28, 2002 By: /s/ ROYCE W. MITCHELL
------------------------------------------------
Royce W. Mitchell
CHIEF FINANCIAL OFFICER
AND CHIEF ACCOUNTING OFFICER
Dated: October 28, 2002 By: /s/ MORTON WOLKOWITZ
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Morton Wolkowitz
DIRECTOR
Dated: October 28, 2002 By: /s/ DAVID J. BREAZZANO
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David J. Breazzano
DIRECTOR
Dated: October 28, 2002 By: /s/ KEVIN P. COLLINS
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Kevin P. Collins
DIRECTOR
Dated: October 28, 2002 By: /s/ W. PHILLIP MARCUM
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W. Phillip Marcum
DIRECTOR
Dated: October 28, 2002 By: /s/ WILLIAM D. FERTIG
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William D. Fertig
DIRECTOR
Dated: October 28, 2002 By: /s/ J. ROBINSON WEST
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J. Robinson West
DIRECTOR
79
I, Francis D. John, certify that:
1. I have reviewed this amendment to the annual report on Form 10-K/A of
Key Energy Services, Inc.;
2. Based on my knowledge, this amendment to the annual report does not
contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this amendment to the annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this amendment to the annual report, fairly
present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods
presented in this amendment to the annual report.
Date: October 28, 2002
/s/ FRANCIS D. JOHN
----------------------------------------------------
Francis D. John
CHIEF EXECUTIVE OFFICER
80
CERTIFICATIONS
I, Royce W. Mitchell, certify that:
1. I have reviewed this amendment to the annual report on Form 10-K/A of
Key Energy Services, Inc.;
2. Based on my knowledge, this amendment to the annual report does not
contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this amendment to the annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this amendment to the annual report, fairly
present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods
presented in this amendment to the annual report.
Date: October 28, 2002
/s/ ROYCE W. MITCHELL
----------------------------------------------------
Royce W. Mitchell
CHIEF FINANCIAL OFFICER
81
SCHEDULE II
KEY ENERGY SERVICES, INC.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
AS OF JUNE 30,
ADDITIONS
BALANCE AT ------------------------------ BALANCE AT
BEGINNING OF CHARGED TO CHARGED TO END OF
YEAR EXPENSES OTHER ACCOUNTS(A) DEDUCTIONS YEAR
------------ ---------- ----------------- ---------- ----------
(IN THOUSANDS)
Allowance for doubtful accounts:
2002............................. $4,082 $ 168 $ -- $ 281 $3,969
2001............................. 3,189 1,263 -- 370 4,082
2000............................. 6,790 1,648 -- 5,249 3,189
82