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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED JUNE 30, 20012002
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ______________ TO
______________------------ ------------
COMMISSION FILE NUMBER 1-8038
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KEY ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)
MARYLAND 04-2648081
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization) Identification No.)
6 DESTA DRIVE, MIDLAND, TEXAS 79705
6 DESTA DRIVE, MIDLAND, TEXAS (Zip Code)
(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
----------------------------TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common Stock, $.10 par value New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
5% Convertible Subordinated Notes Due 2004
------------------------
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months
(or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days. Yes /X/: No / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. / /
The aggregate market value of the Common Shares held by nonaffiliates of the
Registrant as of September 25, 200127, 2002 was approximately $638,579,000.$987,327,248.
Common Shares outstanding at September 25, 2001: 102,305,21527, 2002: 127,432,461
DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Proxy Statement with
respect to the Annual Meeting of Shareholders for the fiscal year ended June
30, 2002 are incorporated by reference in Part III of this report.
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KEY ENERGY SERVICES, INC.
INDEX
PART I.
Item 1. Business....................................................Business..................................................................................... 3
Item 2. Properties.................................................. 9Properties................................................................................... 10
Item 3. Legal Proceedings and Other Actions......................... 10Actions.......................................................... 11
Item 4. Submission of Matters to a Vote of Security Holders......... 10Holders.......................................... 11
PART II.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters....................................... 10Matters.................... 11
Item 6. Selected Financial Data..................................... 11Data...................................................................... 12
Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 12Condition........ 13
Item 7A. Quantitative and Qualitative Disclosures About Market Risk......................................................Risk................................... 20
Item 8. Consolidated Financial Statements and Supplementary Data.... 21Data..................................... 22
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.................................. 60Disclosure......... 59
PART III.
Item 10. Directors and Executive Officers of the Registrant.......... 60Officers............................................................. 59
Item 11. Executive Compensation...................................... 60Compensation....................................................................... 59
Item 12. Security Ownership of Certain Beneficial Owners and Management................................................ 60Management............................... 59
Item 13. Certain Relationships and Related Transactions.............. 60Transactions............................................... 59
Item 14. Disclosure Controls and Procedures........................................................... 59
PART IV.
Item 14.15. Exhibits, Financial Statements and Reports on Form 8-K...... 608-K....................................... 59
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'sII - 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
1,4771,486 well service rigs and 1,4551,719 oilfield service vehicles as of June 30, 2001.2002.
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,
2001.2002. 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
3
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 3
opportunity to capitalize on improved market conditions which existedstrengthen its
position within the industry during fiscal 2001.2001 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, 2001,2002, Key's long-term
funded debt net of cash and capitalized leases ("net funded debt") was
approximately $468,845,000$366,634,000 and its net funded debt to capitalization ratio was
approximately 50%41% as compared to approximately $534,816,000$468,845,000 and 58%50%,
respectively, at June 30, 2000.2001. 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 in conjunctioncombined with a
highly trained and motivated employees.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 2001
FAVORABLE2002
DEPRESSED INDUSTRY CONDITIONS
Operating conditions improveddeclined significantly during fiscal 20012002 as
capital spending by oil and natural gas producers for well servicing and
contract drilling services increased overdecreased from prior year levels. The increaseddecreased
spending was primarily due to higherlower 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 $26.97$23.81 per
barrel and Nymex Henry Hub natural gas prices averaging approximately $5.09$2.77
per MMbtu during fiscal 2001,2002, as compared to an average WTI Cushing price for
light sweet crude of $25.97$26.97 per barrel and an average Nymex Henry Hub natural
gas price of $3.04$5.09 per MMbtu during fiscal 2000.
This increase in2001.
The lower commodity prices during fiscal 20012002 led to a steady,
sequential increaserapid
decrease in the demand for Key's services and equipment during fiscalbeginning in the
December 2001 quarter as Key's customers increasedreduced their exploration and
development activity in Key's primary market areas, enablingareas. 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 to increasewas
successful in minimizing rate concessions; however, the rates it charges for
its services. This increasedecrease in demand
and moderately lower rates resulted in sequential increasesdecreases in revenues, cash
flow and net income in each quarterthe last three quarters of fiscal 20012002 over the same
quarterquarters of fiscal 2000.2001. Key expects demand for its services to remain at or
above currentgradually
improve from its existing levels as long as capital spending by Key's customers remains at
or near their current levels.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.
4
DuringDespite 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. Since June 30,prices; however, between November 2001 however, bothand 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 weakened significantly, falling below
$22.00also improved. Since February 2002, Nymex Henry Hub
prices have improved to $3.05 per barrel and $2.00MMbtu from $2.23 per Mmbtu, respectively.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. In
addition, the terrorist attacks on the World Trade Center and the Pentagon that
occurred on September 11, 2001 threaten to increase the downward pressure on
commodity prices as U.S. fuel consumption decreases due to significantly reduced
air and other travel, the general demand for energy decreases as consumer
anxietyAssuming no further weakensweakening in the U.S. economy
and OPEC faces political pressure to
reduce its price targets for crude oil.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(See Part II-Item
7-Management's Discussion and Analysis of Results of Operations and Financial
Condition).
DEBT REDUCTION
During fiscal 2001,2002, Key significantly reduced its long-term debt and
strengthened its balance sheet. At June 30, 2001,2002, Key's net funded debt was
approximately $468,845,000$366,634,000 and its net funded debt to capitalization ratio was
approximately 50%41% as compared to approximately $534,816,000$468,845,000 and 58%50%,
respectively, at June 30, 2000.2001. Proceeds from the Equity Offering (defined
below) and the Debt Offering (defined below)
and from the exercise of options and warrants,, 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 6, 2001,1, 2002, Key completed thea public offering of $175,000,000$100,000,000 of
8 3/8% Senior Notes Due 2008 at 101.5% of par (the "Debt Offering"). NetThe cash
proceeds from the Debt
Offeringpublic offering, net of fees and expenses, were approximately $170.0 million, which was used to immediately repay
the term loans in full and to repay a portionentire balance of the revolverrevolving loan facility then outstanding under Key's
senior credit facility.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.
5
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 1513 to Consolidated Financial Statements-Business Segment Information).
WELL SERVICING
Key provides a full range of well services, including rig-based
services, oilfield trucking services, fishing and rental tool services, pressure
pumping services and other ancillary oilfield services, necessary to maintain
and workover oil and natural gas producing wells. Rig-based services include:
maintenance of existing wells, workovers of existing wells, completion of newly
drilled wells, recompletion of existing wells (including horizontal
recompletions) and plugging and abandonment of wells at the end of their useful
lives.
5
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.
6
Maintenance services are often performed on a series of wells in
proximity to each other and typically require less than 48 hours per well to
complete. The general demand for maintenance services is closely related to the
total number of producing oil and natural gas wells in a geographic market, and
maintenance services are generally the most stable type of well service
activity.
WORKOVER SERVICES. In addition to periodic maintenance, producing oil
and natural gas wells occasionally require major repairs or modifications,
called "workovers." Workover services are performed to enhance the current
production of existing wells. Such services include extensions of existing wells
to drain new formations either through deepening wellbores to new zones or
through drilling of horizontal lateral wellbores to improve reservoir drainage
patterns. In less extensive workovers, Key's rigs are used to seal off depleted
zones in existing wellbores and access previously bypassed productive zones.
Key's workover rigs are also used to convert former producing wells to injection
wells through which water or carbon dioxide is then pumped into the formation
for enhanced recovery operations. Other workover services include: major
subsurface repairs such as casing repair or replacement, recovery of tubing and
removal of foreign objects in the wellbore, repairing downhole equipment
failures, plugging back the bottom of a well to reduce the amount of water being
produced with the oil and natural gas, cleaning out and recompleting a well if
production has declined, and repairing leaks in the tubing and casing. These
extensive workover operations are normally performed by a well service rig with
a workover package, which may include rotary drilling equipment, mud pumps, mud
tanks and blowout preventers depending upon the particular type of workover
operation. Most of Key's well service rigs are designed for and can be equipped
to perform complex workover operations.
Workover services are more complex and time consuming than routine
maintenance operations and consequently may last from a few days to several
weeks. These services are almost exclusively performed by well service rigs.
The demand for workover services is more sensitive to expectations
relating to, and changes in, oil and natural gas prices than the demand for
maintenance services. As oil and natural gas prices increase, the level of
workover activity tends to increase as operators seek to increase production by
enhancing the efficiency of their wells at higher commodity prices with
correspondingly higher rates of return.
6
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 provideshas established
itself as a leading provider of
7
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. TheseOf 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 alsoused 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. Key also ownsFluid 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 number of salt water disposal wells.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.next and operates a
fleet of hot oilers. Demand and pricing for these services are generally related
to demand for Key's well service and drilling rigs. Fluid hauling and equipment
hauling services are typically priced on a per hour basis while frac tank
rentals typically are billed on a per day basis.
WELL INTERVENTION SERVICES
Through its acquisition of QSI in July 2002, Key expanded its
fishing and rental tool operations and added a pressure pumping business.
These operations comprise Key's Well Intervention Services Division which is
part of the well servicing line of business.
Founded in 1993, QSI's fishing and rental tool operation, Quality
Tubular Services, Inc. ("QTS"), provides fishing and rental tool services to
major and independent oil and natural gas production companies primarily in
the Gulf Coast region of the United States. QTS operates nine 24-hour service
locations and four regional sales offices. The fishing tool supervisors have
extensive experience with downhole problems. In addition, QTS offers a full
line of services and equipment designed for the harsh elements from land to
offshore. The rental tool inventory consists of tubulars, handling tools,
pressure-control equipment and a fleet of power swivels. Key also provides
fishing and rental tools through its Landmark Fishing and Rental Tools
operation in the Mid-Continent region and at various locations throughout the
country.
Key's pressure pumping business operates under the name American Energy
Services, Inc. ("AES"). AES provides stimulation services, cementing services,
nitrogen services, hydro-testing and production chemistry services to oil and
natural gas producers. Key offers a full complement of acidizing technology,
fracturing technology, nitrogen technology and cementing technology services.
With over 64,000 horsepower in cementing and stimulation equipment, AES is one
of the largest U.S. providers of pressure pumping services. AES was established
in December 1996 and operates in the Permian Basin, the San Juan Basin, and the
Mid-Continent Region.
ANCILLARY OILFIELD SERVICES
Key provides ancillary oilfield services, which include among others:
hot
oiling; wireline; frac tank rentals; well site construction; roustabout services; fishing and other tool rentals; blowout preventers (BOPs); and foam units and air
drilling services. Demand and pricing for these services are generally related
to demand for Key's well service and drilling rigs.
CONTRACT DRILLING
Key provides contract drilling services to major oil companies and
independent oil 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 areis equipped with mechanical power systems and havehas 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 7
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.
8
FOREIGN OPERATIONS
Key also operates each of its business segments discussed above in
Argentina, Ontario, Canada and Ontario, Canada.Egypt. Key's foreign operations currently own 2625
well servicing rigs, 5775 oilfield trucks and eightseven drilling rigs in Argentina,
and threefour well servicing rigs, four oilfield trucks and threetwo drilling rigs in Ontario,
Canada.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. No singleOne customer in fiscal 20012002, Occidental Petroleum
Corporation, accounted for 10% or more of Key's consolidated revenues.
COMPETITION AND OTHER EXTERNAL FACTORS
Despite the significant consolidation in the domestic well servicing
industry, there are numerous smaller companies that compete in Key's well
servicing markets. Nonetheless, Key believes that its performance, equipment,
safety, and availability of equipment to meet customer needs and availability of
experienced, skilled personnel is superior to that of its competitors.
In the well servicing markets, an important competitive factor in
establishing and maintaining long-term customer relationships is having an
experienced, skilled and well-trained work force. In recent years, many of Key's
larger customers have placed increased emphasis on the safety records and
quality of the crews, equipment and services provided by their contractors. Key
has, and will continue to devote substantial resources toward employee safety
and training programs. Management believes that many of Key's competitors,
particularly small contractors, have not undertaken similar training programs
for their employees. Management believes that Key's safety record and reputation
for quality equipment and service are among the best in the industry.
In the contract drilling market, Key competes with other regional and
national oil and natural gas drilling contractors, some of which have larger rig
fleets with greater average depth capabilities and a few that have better
capital resources than Key. Management believes that the contract drilling
industry is less consolidated than the well servicing industry, resulting in a
contract drilling market that is more price competitive. Nonetheless, Key
believes that it is competitive in terms of drilling performance, equipment,
safety, pricing, availability of equipment to meet customer needs and
availability of experienced, skilled personnel in those regions in which it
operates.
The need for well servicing and contract drilling fluctuates,
primarily, in relation to the price of oil and natural gas which, in turn, is
driven by the supply of and demand for oil and natural gas. As supply of those
commodities decreases and demand increases, service and maintenance requirements
increase as oil and natural gas producers attempt to maximize the producing
efficiency of their wells in a higher priced environment.
EMPLOYEES
As of June 30, 2001,2002, Key employed approximately 9,3007,850 persons
(approximately 9,2207,746 employees in its well servicing and contract drilling
businesses and 80 in corporate)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.
8
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,
9
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 usKey to liability for the conduct of,
or conditions caused by, others, or for Key's acts, which were in compliance
with all applicable laws at the times such acts were performed. Cleanup costs
and other damages arising as a result of environmental laws, and costs
associated with changes in environmental laws and regulations could be
substantial and could have a material adverse effect on Key's financial
condition. From time to time, claims have been made and litigation has been
brought against Key under such laws. However, the costs incurred in connection
with such claims and other costs of environmental compliance have not had any
material adverse effect on Key's operations or financial statements in the past,
and management is not currently aware of any situation or condition that it
believes is likely to have any such material adverse effect in the future.
Management believes that it conducts Key's operations in substantial compliance
with all material federal, state and local regulations as they relate to the
environment. Although Key has incurred certain costs in complying with
environmental laws and regulations, such amounts have not been material to Key's
financial results during the past three fiscal years.
ITEM 2. PROPERTIES.
Key's corporate headquarters are located in Midland, Texas. Key leases
office space at this location from an independent third party.
WELL SERVICING AND CONTRACT DRILLING
The following table sets forth the type, number and location of the
major equipment owned and operated by Key's operating divisions as of June 30,
2001:2002:
WELL SERVICE/SERVICE AND OILFIELD DRILLING
OPERATING DIVISION WORKOVER RIGS TRUCKS RIGS
-------------------------------------- ------------- -------------- --------- --------
DOMESTIC:
Permian Basin (well servicing)................. 466 357 0..................... 468 450 -
Gulf Coast..................................... 244 338 0
Mid-Continent.................................. 313 285 0Coast......................................... 252 319 -
Mid-Continent...................................... 326 385 -
Four Corners................................... 61 79 17
Eastern........................................ 95 208Corners....................................... 49 91 15
Eastern............................................ 91 253 3
Rocky Mountains................................ 134 54 12
California..................................... 135 24 0Mountains.................................... 131 58 14
California......................................... 138 35 -
Key Energy Drilling (Permian Basin)............................ 0 48 3649 38
--------------------- ------------- --------------
DOMESTIC SUBTOTAL................................ 1,448 1,393 68SUBTOTAL.................................... 1,455 1,640 70
--------------------- ------------- --------------
INTERNATIONAL:
Argentina...................................... 26 57 8
Canada......................................... 3 5 3
TOTALS........................................... 1,477 1,455Argentina.......................................... 25 75 7
Canada............................................. 4 4 2
Egypt.............................................. 2 - -
--------------------- ------------- --------------
INTERNATIONAL SUBTOTAL............................... 31 79 9
--------------------- ------------- --------------
TOTALS............................................... 1,486 1,719 79
===================== ============= ==============
9
The Permian Basin Well Servicing division owns 3536 and leases sixseven
office and yard locations. The Gulf Coast division owns 1614 and leases 18six office
and yard locations. The Mid-Continent division owns 2830 and leases 2022 office and
yard locations. The Four Corners division owns eightsix and leases two office and
yard locations. The Eastern division owns three and leases ten office and yard
locations. The Rocky Mountain division owns 1718 and leases threetwo office and yard
locations. The California division owns one and leases onetwo office and yard
locations. The Permian Basin Drilling division owns two and leases two office
and yard locations. The Argentina division owns twoone and leases one office and
yard locations. The
10
Canadian operation owns one yard location. Odessa Exploration owns interests in
515223 gross (348(172 proved developed) oil propertiesleases and 5357 gross (45(50 proved developed)
gas properties.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 43 to Consolidated Financial Statements--CommitmentsStatements-Commitments and
Contingencies.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Key's common stock is currently traded on the New York Stock Exchange,
under the symbol "KEG". As of June 30, 2001,2002, there were 669645 registered holders
of 101,440,166110,308,463 issued and outstanding shares of common stock, including 416,666
shares of common stock held in treasury (101,023,500(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
20012002 and fiscal 2000,2001, as derived from published sources.
HIGH LOW
---------- --------------- -----
Fiscal Year Ending 2001:2002:
Fourth Quarter............................................ $15 1/3 $9 11/20Quarter....................................... $12.59 $9.63
Third Quarter............................................. 13 13/25 8 1/8Quarter........................................ 11.45 7.20
Second Quarter............................................ 10 1/2 6 13/16Quarter....................................... 9.70 5.99
First Quarter............................................. 11 11/25 7 1/16Quarter........................................ 11.01 5.58
Fiscal Year Ending 2000:2001:
Fourth Quarter............................................ $11 7/8 $8 1/16Quarter....................................... $15.33 $9.55
Third Quarter............................................. 12 1/4 5Quarter........................................ 13.52 8.13
Second Quarter............................................ 5 7/8 3 1/8Quarter....................................... 10.50 6.81
First Quarter............................................. 5 13/16 3 3/8Quarter........................................ 11.44 7.06
There were no dividends paid on Key's common stock during the fiscal
years ended June 30, 2002, 2001 2000 or 1999.2000. 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.
10
RECENT SALES OF UNREGISTERED SECURITIES
Key did not make any unregistered sales of its securities during the
twelve months ended June 30, 20012002 that were not previously included in its
Quarterly Reports filed for such period.
EQUITY COMPENSATION PLAN INFORMATION
The following table summarizes information, as of June 30, 2002, about the
Company's common stock that may be issued upon the exercise of options that
have been granted (i) under equity compensation plans that have been approved
by the Company's shareholders and (ii) outside such plans. The only equity
compensation plan that has been approved by the Company's shareholders is the
Key Energy Group, Inc. 1997 Incentive Plan (the "Incentive Plan"). For a
description of the Incentive Plan, see Note 8 to Consolidated Financial
Statements - Stockholders' Equity. All options not issued under the Incentive
Plan (the "Non-Plan Options") were approved by the Board or the Compensation
Committee under individual option grants (rather than under a separate equity
compensation plan not approved by the Company's shareholders). The Non-Plan
Options (i) expire in ten years, (ii) vest either on the grant date or
ratably over a three-year period following the grant date, (iii) have
exercise prices equal to or greater than the market price at the date of
grant and (iv) have other terms similar to those options granted under the
Incentive Plan.
Number of securities
Number of securities Remaining available for
to be issued upon future issuance under
exercise of Weighted-average equity compensation plans
outstanding options, exercise price of (excluding securities
warrants, and rights outstanding options, reflected in column (a))
(thousands) warrants, and rights (thousands)
Plan Category (a) (b) (c)
- ---------------------------------- ---------------------- ----------------------- --------------------------
Equity compensation plans
approved by the security holders 6,298 $7.41 616 (1)
Equity compensation plans
not approved by the security
holders 3,710 $8.45 0 (2)
Total 10,031 $7.80 409
(1) The number of shares of the Company's common stock available for issuance
under the Incentive Plan on any given date, subject to adjustment in
certain circumstances, is equal to (i) 10% of the number of shares of the
Company's common stock issued and outstanding on the last day of the
calendar quarter immediately preceding such date (provided, however,
that such number cannot decrease from one quarter to the next quarter),
less (ii) the number of shares of the Company's common stock previously
granted under the Incentive Plan through such date, plus (iii) the
number of shares of the Company's common stock previously granted under
the Incentive Plan that have been forfeited through such date.
(2) Because the Non-Plan Options are comprised of individual grants outside
the Incentive Plan, all shares available for issuance under the Non-Plan
Options are reflected in column (a).
11
ITEM 6. SELECTED FINANCIAL DATA.
FISCAL YEAR ENDED JUNE 30,
-----------------------------------------------------------------------------------------------------------------------------
2002 2001 2000 1999(1) 1998
1997
---------- ---------- ---------- --------- --------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
OPERATING DATA:
Revenues....................................Revenues ............................................ $ 802,564 $ 873,262 $ 637,732 $ 491,817 $ 424,543
$165,773
Operating costs:
Direct costs.............................. 574,938 462,386 371,428 293,448 114,598costs (4) .................................. 554,773 582,154 471,169 374,308 296,328
Depreciation, depletion and amortization............................amortization .......... 78,265 75,147 70,972 62,074 31,001
11,076
General and administrative................ 66,071 58,772 53,108 38,987 17,447
Bad debt expense.......................... 1,263 1,648 5,928 826 98
Debt issuance costs....................... -- -- 6,307 -- --
Restructuring charge...................... -- -- 4,504 -- --
Interest..................................administrative (4) .................... 59,494 60,118 51,637 56,156 36,933
Interest .......................................... 43,332 56,560 71,930 67,401 21,476
7,879Foreign 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.........items .......................... 65,257 99,283 (27,976) (78,933) 38,805
14,675
Net income (loss)........................... ................................... 38,146 62,710 (18,959) (53,258) 24,175 9,098
INCOME (LOSS) PER COMMON SHARE:
Basic.....................................Basic ............................................. $ 0.36 $ 0.63 $ (0.23) $ (1.94) $ 1.41
Diluted ........................................... $ 0.81
Diluted...................................0.35 $ 0.61 $ (0.23) $ (1.94) $ 1.23
$ 0.66
Average common shares outstanding:
Basic.....................................Basic ............................................. 105,766 98,195 83,815 27,501 17,153
11,216
Assuming full dilution....................dilution ............................ 107,462 102,271 83,815 27,501 24,024 17,632
Common shares issued at period end..........end .................. 110,308 101,440 97,210 82,738 18,267 12,298
Market price per common share at period end.......................................end ......... $ 10.50 $ 10.84 $ 9.64 $ 3.56 $ 13.12
$ 17.81
Cash dividends paid on common shares........ -- -- -- -- --shares ................ - - - - -
BALANCE SHEET DATA:
Cash........................................Cash ................................................ $ 54,147 $ 2,098 $ 109,873 $ 23,478 $ 25,265
$ 41,704
Current assets..............................assets ...................................... 192,073 206,150 253,589 132,543 127,557
93,333
Property and equipment......................equipment .............................. 1,093,104 1,014,675 920,437 871,940 547,537
227,255
Property and equipment, net.................net ......................... 808,900 793,716 760,561 769,562 499,152
208,186
Total assets................................assets ........................................ 1,242,995 1,228,284 1,246,265 1,148,138 698,640
320,095
Current liabilities.........................liabilities ................................. 96,628 115,553 92,848 73,151 48,029
33,142
Long-term debt, including current portion...portion ........... 443,610 493,907 666,600 699,978 399,779
174,167
Stockholders' equity........................equity ................................ 536,866 476,878 382,887 288,094 154,928
73,179
OTHER DATA:
Adjusted EBITDA(2)..........................EBITDA (2) ................................. 188,465 $ 232,253 $ 116,574 $ 67,281 $ 92,108
$ 33,728
Net cash provided by (used in):
Operating activities...................... 142,717activities .............................. 178,716 143,347 34,860 (13,427) 40,925
843
Investing activities...................... (83,350)activities .............................. (108,749) (83,980) (37,766) (294,654) (306,339)
(80,749)
Financing activities......................activities .............................. (17,315) (167,142) 89,301 306,294 248,975
117,399
Working capital.............................capital ..................................... 95,445 90,597 160,741 59,392 79,528
60,191
Book value per common share(3)..............share (3) ..................... $ 4.704.87 $ 3.944.70 $ 3.473.94 $ 8.483.47 $ 5.958.48
--------------------------
(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
11
TO COMPANIES IN THE
SAME INDUSTRY AND OF A COMPANY'S ABILITY TO SERVICE OR INCUR DEBT. MANAGEMENT
INTERPRETS TRENDS INDICATED BY CHANGES IN ADJUSTED EBITDA AS AN INDICATOR OF THE
EFFECTIVENESS OF ITS STRATEGIES IN ACHIEVING REVENUE GROWTH AND CONTROLLING
DIRECT AND INDIRECT COSTS OF SERVICES PROVIDED. INVESTORS SHOULD CONSIDER THAT
THIS MEASURE DOES NOT TAKE INTO CONSIDERATION DEBT SERVICE, INTEREST EXPENSES,
COSTS OF CAPITAL, IMPAIRMENTS OF LONG LIVED ASSETS, DEPRECIATION OF PROPERTY,
THE COST OF REPLACING EQUIPMENT OR INCOME TAXES. ADJUSTED EBITDA SHOULD NOT BE
CONSIDERED AS AN ALTERNATIVE TO NET INCOME, INCOME BEFORE TAXES, CASH FLOWS FROM
OPERATING ACTIVITIES OR ANY OTHER MEASURE OF FINANCIAL PERFORMANCE PRESENTED IN
ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES AND IS NOT INTENDED TO
REPRESENT CASH FLOW. ADJUSTED EBITDA MAY NOT BE COMPARABLE TO SIMILARLY TITLED
MEASURES OF OTHER COMPANIES.
(3) BOOK VALUE PER COMMON SHARE IS STOCKHOLDERS' EQUITY AT PERIOD END DIVIDED BY
THE NUMBER OF ISSUED COMMON SHARES AT PERIOD END.
(4) INCLUDES UNUSUAL ITEMS OF APPROXIMATELY $8.5 MILLION FOR DIRECT COSTS AND
APPROXIMATELY $1.0 MILLION FOR GENERAL AND ADMINISTRATIVE DURING FISCAL 2002
AS PREVIOUSLY DISCUSSED IN THE COMPANY'S AUGUST 20, 2002 PRESS RELEASE.
12
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.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. Please note that certainCertain reclassifications have
been made to the fiscalconsolidated financial statements for the years ended June 30,
2001 and 2000 and 1999 financial data presented below to conform to the fiscal 2001year end June 30, 2002 presentation. The
reclassifications consist primarily of reclassifying oilcertain items from general
and natural gas productionadministrative 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 expenses. Oilnet 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 natural gas productionservices partially offset by higher pricing.
CONTRACT DRILLING. Contract drilling revenues for the year ended June
30, 2002 decreased $20,562,000, or 19.1%, to $87,077,000 from $107,639,000 in
fiscal 2001. The decrease was due to lower demand for the Company's contract
drilling equipment and services partially offset by higher pricing.
OPERATING EXPENSES
WELL SERVICING. Well servicing expenses for the year ended June 30,
2002 decreased $10,643,000, or 2.1%, to $489,681,000 from $500,324,000 in fiscal
2001. The decrease in expenses is due to lower activity levels partially offset
by higher insurance costs primarily in workers compensation and health care.
Despite the decreased costs, well servicing expenses as a percentage of well
servicing revenues increased from 66.0% for fiscal 2001 to 69.3% for fiscal 2002
primarily due to the increase in insurance costs.
CONTRACT DRILLING. Contract drilling expenses for the year ended June
30, 2002, decreased $16,805,000, or 21.7%, to $60,561,000 from $77,366,000 in
fiscal 2001. The decrease is due to lower activity levels partially offset by
higher insurance costs primarily in workers compensation and health care.
Contract drilling expenses as a percentage of contract drilling revenues
decreased from 71.9% in fiscal 2001 to 69.5% in fiscal 2002. The margin
improvement is due to improved
13
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 expenses have been reclassified to other revenuesdollar-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 becauseand the effects of state and
local taxes.
CASH FLOW
The Company's net cash provided by operating activities for the year
ended June 30, 2002 increased $35,369,000 to $178,716,000 from $143,347,000 in
fiscal 2001. The increase, despite lower net income in fiscal 2002, is primarily
due to a decrease in accounts receivable in fiscal 2002 compared to an increase
in accounts receivable in fiscal 2001.
The Company's net cash used in investing activities for the year ended
June 30, 2002 increased $24,769,000 to
14
$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
does not believe this
business segment is materialcontinued 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 Company's consolidated financial statements.
RESULTS OF OPERATIONSyear 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 (see Part I--Item--Major Developments During Fiscal
2001--Favorable Industry Conditions).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.
12
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 $93,168,000,$91,601,000, or 23.3%22.4%, to $493,108,000$500,324,000 from $399,940,000$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 percentagepercent of well servicing revenues decreased from 71.5%73.1%
for fiscal 2000 to 65%66.0% for fiscal 2001. The margin improvement is due to
improved operating efficiencies and the effects of higher pricing.
CONTRACT DRILLING. Contract drilling expenses for the year ended June
30, 2001, increased $19,067,000, or 32.7%, to $77,366,000 from $58,299,000 in
fiscal 2000. The increase is due to higher utilization of the Company's contract
drilling equipment, higher labor costs and the overall increase in the Company's
contract drilling business. Despite the increased costs, contract drilling
expenses as a percentage of contract drilling revenues decreased from 85.2% in
fiscal 2000 to 71.9% in fiscal 2001. The margin improvement is due to improved
operating efficiencies and the effects of higher pricing.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
The Company's depreciation, depletion and amortization expense for the
year ended June 30, 2001 increased $4,175,000, or 5.9%, to $75,147,000 from
$70,972,000 in fiscal 2000. The increase is due to higher capital expenditures
15
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 $7,299,000,$8,481,000, or 12.4%16.4%, to $66,071,000$60,118,000 from $58,772,000$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 9.2%8.1% in fiscal 2000 to 7.6%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.
BAD DEBT EXPENSE
The Company's bad debt expense for the year ended June 30, 2001 decreased
$385,000, or 23.4%, to $1,263,000 from $1,648,000 in fiscal 2000. The decrease
was primarily due to improved industry conditions for Key's customers and, to a
lesser extent, the centralization of the Company's internal credit approval
process.
EXTRAORDINARY GAIN
During 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 issuanceissue costs, all of which resulted in an after-tax
extraordinary gain of $429,000.
13
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 37.2%37.3% and 26.5%(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 $107,857,000$108,487,000 to $142,717,000$143,347,000 from $34,860,000 in
fiscal 2000. The increase is due to higher revenues resulting from increased
demand for the Company's equipment and services and higher pricing, partially
offset by higher operating and general and administrative expenses resulting
from increased business activity.
The Company's net cash used in investing activities for the year ended
June 30, 2001 increased $45,584,000$46,214,000 to $83,350,000$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 byin 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 Debt OfferingCompany's fiscal 2001 debt offering and the exercise of
stock options and warrants.
FISCAL YEAR ENDED JUNE 30, 2000 VERSUS FISCAL YEAR ENDED JUNE 30, 1999
The Company's results of operations for the year ended June 30, 2000 reflect
the impact of the industry recovery during such period resulting from increased
commodity prices which in turn caused increased demand for the Company's
equipment and services during fiscal 2000. The positive impact of this increased
demand on the Company's operating results was partially offset by increased
operating expenses incurred as a result of the increase in the Company's
business activity.
THE COMPANY
Revenues for the year ended June 30, 2000 increased $145,915,000, or 29.7%,
to $637,732,000 from $491,817,000 in fiscal 1999, while net income for fiscal
2000 increased $34,299,000 to a net loss of $18,959,000 from a net loss of
$53,258,000 in fiscal 1999. The increase in revenues is due to improved
operating conditions and higher rig hours, the full year effect of the
acquisitions completed during the early portion of fiscal 1999 and, to a lesser
extent, higher pricing. The decrease in net loss is the result of improved
operating conditions, higher pricing, and cost reduction initiatives. In
addition, fiscal 1999 included non-recurring charges for debt issuance costs and
restructuring initiatives as well as higher bad debt expense.
OPERATING REVENUES
WELL SERVICING. Well servicing revenues for the year ended June 30, 2000
increased $125,835,000 or 29%, to $559,492,000 from $433,657,000 in fiscal 1999.
The increase was due to increased demand for the Company's well servicing
equipment and services, the full year effect of the acquisitions completed
during the early portion of fiscal 1999 and, to a lesser extent, higher pricing.
CONTRACT DRILLING. Contract drilling revenues for the year ended June 30,
2000 increased $17,815,000, or 35.2%, to $68,428,000 from $50,613,000 in fiscal
1999. The increase was due to increased demand for the Company's contract
drilling equipment and services, the full year effect of the acquisition
completed during the early portion of fiscal 1999 and, to a lesser extent,
higher pricing.
14
OPERATING EXPENSES
WELL SERVICING. Well servicing expenses for the year ended June 30, 2000
increased $74,975,000, or 23.1%, to $399,940,000 from $324,965,000 in fiscal
1999. The increase in expenses is due to higher utilization of the Company's
well servicing equipment, higher labor costs and the overall increase in the
Company's well servicing business. Despite the increased costs, well servicing
expenses as a percent of well servicing revenues decreased from 74.9% for fiscal
1999 to 71.5% for fiscal 2000. The margin improvement is due to improved
operating efficiencies and the effects of higher pricing.
CONTRACT DRILLING. Contract drilling expenses for the year ended June 30,
2000, increased $14,743,000, or 33.8%, to $58,299,000 from $43,556,000 in fiscal
1999. The increase is due to higher utilization of the Company's contract
drilling equipment, higher labor costs and the overall increase in the Company's
contract drilling business. Despite the increased costs, contract drilling
expenses as a percentage of contract drilling revenues decreased from 86.1% in
fiscal 1999 to 85.2% in fiscal 2000. The margin improvement is due to improved
operating efficiencies and the effects of higher pricing.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
The Company's depreciation, depletion and amortization expense for the year
ended June 30, 2000 increased $8,898,000, or 14.3%, to $70,972,000 from
$62,074,000 in fiscal 1999. The increase is due to higher capital expenditures
incurred during fiscal 2000 as the Company refurbished equipment and increased
utilization of its contract drilling equipment (which it depreciates partially
based on utilization).
GENERAL AND ADMINISTRATIVE EXPENSES
The Company's general and administrative expenses for the year ended
June 30, 2000 increased $5,664,000, or 10.7%, from $53,108,000 to $58,772,000 in
fiscal 2000. The increase was due to higher administrative costs necessitated by
the growth of the Company's operations as a result of the fiscal 1999
acquisitions and improved industry conditions. Despite the increased costs,
general and administrative expenses as a percentage of total revenues declined
from 10.8% in fiscal 1999 to 9.2% in fiscal 2000.
INTEREST EXPENSE
The Company's interest expense for the year ended June 30, 2000 increased
$4,529,000, or 6.7%, to $71,930,000 from $67,401,000 in fiscal 1999. The
increase was primarily due to the full year effect of the debt incurred in
connection with the acquisitions completed during the early portion of fiscal
1999, and, to a lesser extent, higher interest rates during fiscal 2000
partially offset by the impact of the long-term debt reduction during fiscal
2000.
BAD DEBT EXPENSE
The Company's bad debt expense for the year ended June 30, 2000 decreased
$4,280,000, or 72.2%, to $1,648,000 from $5,928,000 in fiscal 1999. The decrease
was primarily due to improved industry conditions for Key's customers and, to a
lesser extent, the centralization of the Company's internal credit approval
process.
EXTRAORDINARY GAIN
During the fourth quarter of fiscal 2000, the Company repurchased
$10,190,000 of its 5% Convertible Subordinated Notes which resulted in an
after-tax gain of $1,611,000.
15
INCOME TAXES
The Company's income tax benefit for the year ended June 30, 2000 decreased
$18,269,000 to $7,406,000 from $25,675,000 in fiscal 1999. The decrease in
income tax benefit is due to the decrease in pretax loss. The Company's
effective tax benefit rate for fiscal 2000 and 1999 was 26.5% and 32.5%,
respectively. The fiscal 2000 effective tax benefit rate is different from the
statutory rate of 35% principally because of certain non-deductible goodwill
amortization, other non-deductible expenses and state and local taxes. The
decrease in the fiscal 2000 effective tax benefit rate was due to an increase in
the amount of non-deductible expenses, primarily as a result of the full year
effect of the goodwill amortization of the acquisitions completed during the
early portion of fiscal 1999.
CASH FLOW
The Company's net cash provided by operating activities for the year ended
June 30, 2000 increased $48,287,000 to a $34,860,000 from a use of $13,427,000
in fiscal 1999. The increase is due to higher revenues resulting from increased
demand for the Company's equipment and services, the full year effect of the
acquisitions completed during the early portion of fiscal 1999 and, to a lesser
extent, higher pricing, partially offset by higher operating and general and
administrative expenses resulting from increased business activity.
The Company's net cash used in investing activities for the year ended
June 30, 2000 decreased $256,888,000, or 87.2%, to $37,766,000 from $294,654,000
in fiscal 1999. The decrease is due to no acquisitions having occurred during
fiscal 2000 partially offset by higher capital expenditures.
The Company's net cash provided by financing activities for the year ended
June 30, 2000 decreased $216,993,000, or 70.8%, to $89,301,000 from $306,294,000
in fiscal 1999. The decrease is primarily the result of significantly decreased
borrowings during fiscal 2000 and, to a lesser extent, the repayment of
long-term debt partially offset by proceeds from the equity offering and the
volumetric production payment completed in fiscal 2000.
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically funded its operations, acquisitions,
capital expenditures and working capital requirements from cash flow from
operations, bank borrowings and the issuance of equity and long-term debt. The
Company believes that its current reserves of cash and cash equivalents,
availability of its existing credit lines, access to capital markets and
internally generated cash flow from operations are sufficient to finance the
cash requirements of its current and future operations.
16
The Company's cash and cash equivalents decreased $107.8 millionincreased $52,049,000 to
$2.1 million$54,147,000 as of June 30, 20012002 from $109.9 million$2,098,000 as of June 30, 2000, which
included $100.6 million in net proceeds from the Company's equity offering which
closed on June 30, 2000 and had not yet been applied to debt reduction.
The Company projects approximately $65 million for capital expenditures for
fiscal 2002 as compared to $82 million and $38 million in fiscal 2001 and 2000,
respectively.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, 20012002 the Company had working capital (excluding the
current portion of long-term debt)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 compared to working capital
(excluding the current portion of long-term debt) of approximately $175,396,000,
which includes cash and cash equivalents of approximately $109,873,000, as of June 30, 2000.2001. The decreaseincrease in
working capital is primarily due to the use of
the net cash proceeds of $100,571,000 from the June 30, 2000 equity offering to
repay long-term debt during the fiscal year
16
ended June 30, 2001. Working capital at June 30, 2001, excluding the changean increase in cash increased from June 30, 2000 due to continuing improvementand cash equivalents, a
decrease in operating
resultsaccounts payable and timing differences related to cash receiptsis partially offset by a decrease in accounts
receivable and disbursements.inventories.
LONG-TERM DEBT
Other than capital lease obligations and miscellaneous notes
payable, as of June 30, 2001,2002, 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, and (v) a series of 9 3/8% Senior Notes Due 2007.2004.
SENIOR CREDIT FACILITY
As of June 30, 2001,During fiscal 2002, the Company had a senior credit facility (the
"Prior Senior Credit Facility") with a syndicate of banks led by PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas, N.A., as
Collateral Agent, PNC Capital Markets, Inc., as Arranger, and the other lenders
named from time to time parties thereto (as subsequently amended, the "Senior
Credit Facility"), which consisted of a $125 million$100,000,000 revolving loan facility. In addition,
up to $20 million$30,000,000 of letters of credit cancould be issued under the Prior Senior
Credit Facility, but any outstanding letters of credit reducereduced 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 commitment to make revolving
loans was reduced to $100Company drew down approximately $43 million on SeptemberJanuary
14, 2001 and will reduce2002 in order to $75 million on September 14,redeem the 14% Senior Subordinated Notes. The funds were
repaid with the issuance of additional 8 3/8% Notes in March 2002.
The revolving loan bore interest based upon, at the Company's option,
the prime rate plus a variable margin of 0.75% to 2.00% or a Eurodollar rate
plus a variable margin of 2.25% to 3.50%.
On July 15, 2002, the Company entered into a Third Amended and
Restated Credit Agreement (the "New Senior Credit Facility"). The New Senior
Credit Facility consists of a $150,000,000 revolving loan facility with a
$40,000,000 sublimit for letters of credit. The loans are secured by most of
the tangible and intangible assets of the Company. The revolving loan
commitment will terminate on September 14, 2003,July 15, 2005 and all the revolving loans must be
paid on or before that date. The revolving loan bearsloans bear interest at rates based upon, at
the Company's option, either the prime rate plus a variable margin ranging fromof 0.00% to 0.75% to 2.00%
or a Eurodollar rate plus a variable margin ranging from 2.25%of 1.25% to 3.50%, in each case
depending upon the ratio of the Company's total debt (less cash on hand over
$5 million) to the Company's trailing 12-month EBITDA, as adjusted.
During fiscal 2001, the Company repaid in full approximately $198.9 million
under the term loans which were originally included in the2.75%. The New Senior
Credit Facility while decreasinghas customary affirmative and negative covenants including a
maximum leverage ratio, a minimum fixed charge coverage ratio and a minimum
net borrowings under the revolver by $91 million. As a
result, at June 30, 2001 the principal amounts outstanding under (i) the
original term loans were fully repaidworth, as well as limitations on liens and (ii) the revolver was approximately
$2.0 million. Additionally, at June 30, 2001, the Company had outstanding
letters of credit totaling approximately $12.0 million related to its workers
compensation insurance program. Since June 30, 2001 the principal amount
outstanding under the revolver has increased to $38.0 million as of
September 25, 2001. These funds were used to repurchase certain long-term debt
of the Company.
See Note 5 to Consolidated Financial Statements-Long Term Debt for further
discussion of the Senior Credit Facility.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 loansloan 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, ranking equally with the
Company's other senior unsecured indebtedness.obligations.
The 8 3/8% Senior Notes are effectively subordinated to Key's secured
indebtedness which includes borrowings under the Senior Credit Facility and the Dawson 9 3/8% Senior Notes.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
17
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.
17
At June 30, 2001, $175,000,0002002, $275,000,000 principal amount of the 8 3/8%
Senior Notes remained outstanding. The 8 3/8% Senior Notes payrequire semi-annual
interest semi-annuallypayments 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 common stockthe 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 $148.6 million$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 maywas 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 at 114% of par
plus accrued interest. On June 11,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, leaving
$139,687,000interest. 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 outstanding as of June 30, 2001.the 14% Senior Subordinated
Notes at a price of 114% of the principal amount plus accrued interest. This
transaction resulted in an extraordinary loss before taxes of approximately
$8,468,000. Also, during fiscal 2002, the Company purchased and canceled
$6,784,000 principal amount of the 14% Senior Subordinated Notes at a price of
116% of the principal amount plus accrued interest. These transactions resulted
in extraordinary losses before taxes of approximately $1,821,000.
The Unit Warrants have separated from the 14% Senior Subordinated Notes
and became exercisable on January 25, 2000. On the date of issuance, the value
of the Unit Warrants was estimated at $7,434,000 and is classified as a discount
to the 14% Senior Subordinated Notes on the Company's consolidated balance
sheet. The discount is being amortized to interest expense over the term of the
14% Senior Subordinated Notes. The 14% Senior Subordinated Notes mature and the
Unit Warrants expire on January 15, 2009. The 14% Senior Subordinated Notes are
subordinate to the Company's senior indebtedness, which includes borrowings
under the Senior Credit Facility the Dawson 9 3/8% Senior Notes and the 8 3/8% Senior Notes.
At June 30, 2001, $139,687,0002002, $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 $10,500,000$9,778,000 and $6,825,000 were made on July 15, 20002001 and
January 15, 2001,2002, respectively. As of June 30, 2001, 62,5002002, 63,500 Unit Warrants had
been exercised, producing approximately $4,173,000 of proceeds to the Company
and leaving 87,50086,500 Unit Warrants outstanding. Since June 30, 2001, the Company repurchased (and
canceled) an additional $6,784,000 principal amount of the 14% Senior
Subordinated Notes, leaving $132,903,000 outstanding as of September 25, 2001.
5% CONVERTIBLE SUBORDINATED NOTES
In late September and early October 1997, the Company completed a
private placement of $216 million$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, the Dawson
9 3/8% Senior Notes and the
8 3/8% Senior Notes. The 5% Convertible Subordinated Notes are convertible, at
the holder's option, into shares of the Company's common stock at a conversion
price of $38.50 per share, subject to certain adjustments. The 5% Convertible
Subordinated Notes are redeemable, at the Company's option, on and after
September 15, 2000, in whole or part, together with accrued and unpaid interest.
The initial redemption price is 102.86% for the year beginning September 15,
2000 and declines ratably thereafter on an annual basis.
18
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 $158,426,000$49,951,000 principal amount of the 5% Convertible Subordinated Notes
outstanding at June 30, 2001.2002. These repurchases resulted in extraordinary
gains before taxes of approximately $5,633,000. Since June 30, 2001,2002, the
Company has repurchased (and canceled) an additional $46,493,000$204,000 principal
amount of the 5% Convertible Subordinated Notes, leaving $111,933,000$49,747,000
outstanding as of September 25, 2001.30, 2002. Interest on the 5% Convertible
Subordinated Notes is payable on March 15 and September 15. Interest of approximately $4,890,000 and $4,815,000 million was
paid on September 15 2000 and March 15, 2001, respectively.
DAWSON 9 3/8% SENIOR NOTES
As a result of the Dawson acquisition, the Company, its subsidiaries and
U.S. Trust Company of Texas, N.A., as trustee ("U.S. Trust"), entered into a
Supplemental Indenture dated September 21, 1998 (the "Supplemental Indenture"),
pursuant to which the Company assumed the obligations of Dawson under the
Indenture dated February 20, 1997 (the "Dawson Indenture") between Dawson and
U.S. Trust. The senior notes due 2007 (the "Dawson 9 3/8% Senior Notes") issued
pursuant to the Dawson Indenture were equally and ratably secured with the
obligations under the Senior Credit Facility. As a result of a mandatory tender
offer made in connection with the Dawson acquisition and subsequent repurchases,
only $1,106,000 principal amount of Dawson 9 3/8% Senior Notes remained
outstanding at June 30, 2000.
During the quarter ended September 30, 2000, the Company repurchased (and
canceled) $800,000 principal amount of Dawson 9 3/8% Senior Notes. During the
quarter ended June 30, 2001, the Company repurchased an additional $60,000
principal amount of the Dawson 9 3/8% Senior Notes, leaving $246,000 principal
amount of the Dawson 9 3/8% Senior Notes outstanding at June 30, 2001. Interest
on the Dawson 9 3/8% Senior Notes is payable on February 1 and August 1 of each year.
Interest of approximately $52,000$3,027,000 and $14,000$1,259,000 was paid on AugustSeptember 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 2000to the consolidated financial statements included
herein.
Certain of the policies require management to make significant and
February 1, 2001, respectively.
7% CONVERTIBLE SUBORDINATED DEBENTURESsubjective estimates which are sensitive to deviations of actual results from
management's assumptions. In July 1996,particular, management makes estimates regarding
the fair value of the Company's reporting units in assessing potential
impairment of goodwill. In addition, the Company completed a private placementmakes estimates regarding
future undiscounted cash flows from the future use of $52,000,000
principallong-lived assets whenever
events or changes in circumstances indicate that the carrying amount of 7% Convertible Subordinated Debentures due 2003 (the "7%
Convertible Subordinated Debentures"). Duringa
long-lived asset may not be recoverable.
In assessing impairment of goodwill, the quarter ended September 30,
2000, $985,000 principalCompany 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 7% Convertible Subordinated Debentures
were surrendered for conversion by the holders thereof and 101,025 shares of
common stock were issued on September 1, 2000 in connection with the conversion.
On September 1, 2000, the remaining $15,000 principal amountCompany has estimated future
undiscounted net cash flows from use of the outstanding
7% Convertible Subordinated Debentures was redeemed at 103%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 principal
amount plus accrued interest, leaving none outstanding. Interest onasset could change if actual prices and costs differ due to
industry conditions or other factors affecting the 7%
Convertible Subordinated Debentures is payable on January 1 and July 1 of each
year. Interest of approximately $35,000 was paid on July 1, 2000.
IMPACT OFCompany's performance.
RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS
The FASB recentlyRecently the Financial Accounting Standards Board, ("FASB") issued
StatementsStatement of Financial Accounting Standards No. 141 "Business Combinations", No.142 "Goodwill and Other Intangible Assets"
and No. 143, "AccountingAccounting for Asset
Retirement Obligations"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 141
requiresNo. 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 all business combinations initiated after June 30, 2001certain lease modifications that
have economic effects similar to sale-leaseback transactions be accounted for underin
the purchase method. Statement 142 requires that goodwillsame manner as sale-leaseback transactions. Upon adoption of SFAS 145, the
Company will no longer be amortizedrecord the gains and losses from the extinguishment of
debt as extraordinary items. The impact of the adoption of SFAS 145 to earnings, but instead be reviewed for impairment. The
standard is effective for fiscal years beginning after December 15, 2001. Early
adoption is permitted for entities with fiscal years beginning after March 15,
2001, provided the
first interim financial statements have not previously been
issued. Statement 143Company will depend
19
on the Company's early retirements of debt. SFAS 146 establishes requirements
for thefinancial accounting of
removal-typeand reporting for costs associated with asset retirements. The standardexit or
disposal activities. SFAS 143 is effective for fiscal years beginning after June
15, 2002, with earlier applicationadoption 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
19
Company is currently assessing
the impact of these statementsstandards on its consolidated financial statements and whether to early adopt Statement 142 in
the first quarter of fiscal 2002.statements.
IMPACT OF INFLATION ON OPERATIONS
Management is of the opinion that inflation has not had a significant
impact on Key's business.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Special Note: Certain statements set forth below under this caption
constitute "forward-looking statements". See "Special Note Regarding
Forward-Looking Statements" for additional factors relating to such statements.
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about Key's potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in foreign currency exchange risk, interest rates
and oil and natural gas prices. The disclosures are not meant to be precise
indicators of expected future losses, but rather indicators of reasonably
possible losses. This forward-looking information provides indicators of how Key
views and manages its ongoing market risk exposures.
INTEREST RATE RISK
At June 30, 2001,2002 Key had long-term debt outstanding of $493,907,000.$443,610,000. Of
this amount, $468,943,000$420,781,000 or 94.9%, bears interest at fixed rates as follows:
BALANCE AT
6/30/01
-----------JUNE 30, 2002
----------------
(THOUSANDS)
8 3/8%8 % Senior Notes Due 2008................................ $175,0002008..................................... $276,433
14% Senior Subordinated Notes Due 2009............................ 94,257
5% Convertible Subordinated Notes Due 2004.................. 158,426
14% Senior Subordinated Notes Due 2009...................... 134,466
Dawson 9 3/8% Senior Notes Due 2007......................... 2462004........................ 49,951
Other (rates generally ranging from 8.0% to 8.5%(at approximately 8%)........... 805
--------
$468,943
========....................................... 140
----------------
$420,781
================
The remaining $24,964,000 of$22,829,000 debt outstanding as of June 30, 20012002 bears
interest at floating rates which averaged approximately 9.34%6.66% at June 30, 2001.2002.
A 10% increase in short-term interest rates on the floating-rate debt
outstanding at June 30, 20012002 would equal approximately 9367 basis points. Such an
increase in interest rates would increase Key's fiscal 20022003 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
20
subsidiaries are currently not exposed to foreign currency risk, as Argentina's
currency iswere tied to the U.S. dollar.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 isare based on the U.S. dollar equivalent of such amounts measured in
Canadian dollars. Assets and liabilities of the Canadian operations are
translated to U.S. dollars using the applicable exchange rate as of the end of a
reporting period. Revenues expenses and cash flowexpenses are translated using the average
exchange rate during the reporting period.
A 10% change in the Canadian-to-U.S. Dollar exchange rate would not be
material to the net assets, net earnings or cash flows of Key.
20
the Company.
COMMODITY PRICE RISK
Key's major market risk exposure for its oil and natural gas production
operations is in the pricing applicable to its oil and natural gas sales.
Realized pricing is primarily driven by the prevailing worldwide price for crude
oil and spot market prices for natural gas. Pricing for oil and natural gas
production has been volatile and unpredictable for several years.
The Company periodically hedges a portion of its oil and natural gas
production through collar and option agreements. The purpose of the hedges is to
provide a measure of stability in the volatile environment of oil and natural
gas prices and to manage exposure to commodity price risk under existing sales
commitments. The Company's risk management objective is to lock in a range of
pricing for expected production volumes. This allows the Company to forecast
future earnings within a predictable range. The Company meets this objective by
entering into collar and option arrangements which allow for acceptable cap and
floor prices.
As of June 30, 2001,2002, Key had oil and natural gas price collars and
put options in place, as detailed in the following table. The total fiscal
20012002 hedged oil and natural gas volumes represent approximately 32%41% and 20%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, 20012002 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, 20012002 and
2000:2001:
MONTHLY INCOME STRIKE PRICE
------------------------------------ PER BBL/MMBTU
OIL NATURAL GAS --------------------------------
(BBLS) (MMBTU) TERM FLOOR CAP FAIR VALUE
-------- ----------- ---------------------- -------- -------------- ------- ---- ----- --- ----------
At June 30, 20012002
Oil Collar..........Put........... 5,000 --- Mar 20012002-Feb 2003 $22.00 - Feb 2002 $19.70 $ 23.70 $(115,000)$24,000
Oil Put............. 5,000 --Put........... 4,000 - Mar 20022003-Feb 2004 $21.00 - Feb 2003 22.00 -- 141,000$118,000
Gas Collar.......... -- 40,000 Mar 2001Put........... - Feb 2002 2.40 2.91 (229,000)
Gas Put............. -- 75,000 Mar 20022002-Feb 2003 $3.00 - Feb 2003 3.00 -- 894,000$104,000
At June 30, 20002001
Oil Collars......... 4,000 -- May 2000Collar........ 5,000 - Feb 2001 $22.20 $ 26.50 $(118,000)Mar 2001-Feb 2002 $19.70 $23.70 ($115,000)
Oil Put........... 5,000 --- Mar 20012002-Feb 2003 $22.00 - Feb 2002 19.70 23.70 (140,000)$141,000
Gas Collars......... -- 30,000 May 2000Collar........ - Feb 2001 2.60 3.19 (272,000)
-- 40,000 Mar 20012001-Feb 2002 $2.40 $2.91 ($229,000)
Gas Put........... - Feb 2002 2.40 2.91 (248,000)75,000 Mar 2002-Feb 2003 $3.00 - $894,000
(The strike prices for the oil collars and putputs are based on the NYMEX spot
price for West Texas Intermediate; the strike prices for the natural gas collars
are based on the Inside FERC-West Texas Waha spot price; the strike price for
the natural gas put is based on the Inside FERC-El Paso Permian spot price.)
21
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 2000 andfor the years ended June
30, 2002, 2001 2000 and 1999.2000.
Also included is the report of KPMG LLP, independent certified public
accountants, on such consolidated financial statements as of June 30, 20012002 and
20002001 and for the years ended June 30, 2002, 2001 2000 and 1999.
21
2000.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Consolidated Balance Sheets.................................Sheets.......................................... 23
Consolidated Statements of Operations.......................Operations................................ 24
Consolidated Statements of Comprehensive Income.............Income...................... 25
Consolidated Statements of Cash Flows.......................Flows................................ 26
Consolidated Statements of Stockholders' Equity.............Equity...................... 27
Notes to Consolidated Financial Statements..................Statements........................... 28
Independent Auditors' Report................................ 59Report......................................... 58
22
KEY ENERGY SERVICES, INC.
CONSOLIDATED BALANCE SHEETS
JUNE 30, 20012002 JUNE 30, 20002001
------------- -------------
(THOUSANDS, EXCEPT SHARE DATA)
ASSETS
Current assets:
Cash and cash equivalents.................................equivalents ................................................... $ 2,09854,147 $ 109,8732,098
Accounts receivable, net of allowance for doubtful accounts, ($4,082--2001, $3,189--2000)...................$3,969
and $4,082, at June 30, 2002 and June 30, 2001, respectively ............. 117,907 177,016
123,203
Inventories...............................................Inventories ................................................................. 7,776 16,547 10,028
Income taxes receivable................................... -- 5,588
Prepaid expenses and other current assets.................assets ................................... 12,243 10,489
4,897
---------- --------------------- -----------
Total current assets........................................assets .......................................................... 192,073 206,150
253,589
---------- --------------------- -----------
Property and equipment:
Well servicing equipment..................................equipment .................................................... 776,271 723,724 668,107
Contract drilling equipment...............................equipment ................................................. 124,191 119,122
105,454
Motor vehicles............................................vehicles .............................................................. 68,977 64,907 55,042
Oil and gas properties and other related equipment, successful efforts
method...............................method .................................................................... 44,439 44,245 43,855
Furniture and equipment...................................equipment ..................................................... 38,979 24,865 11,013
Buildings and land........................................land .......................................................... 40,247 37,812
36,966
---------- --------------------- -----------
Total property and equipment................................equipment .................................................. 1,093,104 1,014,675 920,437
Accumulated depreciation & depletion........................depletion .......................................... (284,204) (220,959)
(159,876)
---------- --------------------- -----------
Net property and equipment..................................equipment .................................................... 808,900 793,716
760,561
---------- --------------------- -----------
Goodwill, net of accumulated amortization, ($28,168--2001,
$18,849--2000)..........................................$27,856 and $28,168, at
June 30, 2002 and June 30, 2001, respectively .............................. 201,069 189,875 198,633
Deferred costs, net.......................................net ........................................................... 12,580 17,624
18,855
Notes receivable--related parties.........................receivable - related parties ............................................ 274 6,050
5,150
Other assets..............................................assets .................................................................. 28,099 14,869
9,477
---------- --------------------- -----------
Total assets................................................ $1,228,284 $1,246,265
========== ==========assets .................................................................. $ 1,242,995 $ 1,228,284
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable..........................................payable ............................................................ $ 24,625 $ 42,544
$ 35,801
Other accrued liabilities.................................liabilities ................................................... 49,465 48,923
26,398
Accrued interest..........................................interest ............................................................ 14,864 16,140 15,994
Current portion of long-term debt.........................debt ........................................... 7,674 7,946
14,655
---------- --------------------- -----------
Total current liabilities...................................liabilities ..................................................... 96,628 115,553
92,848
---------- --------------------- -----------
Long-term debt, less current portion........................ 485,961 651,945portion .......................................... 420,717 470,578
Capital lease obligations, less current portion ............................... 15,219 15,383
Deferred revenue............................................revenue .............................................................. 10,001 14,104 17,031
Non-current accrued expenses................................expenses .................................................. 13,574 8,388 1,847
Deferred tax liability......................................liability ........................................................ 149,990 127,400 99,707
Commitments and contingencies............................... -- --contingencies
Stockholders' equity:
Common stock, $0.10 par value; 200,000,000 shares authorized, 101,440,166110,308,463 and
97,209,504101,440,166 shares issued, respectively at June
30, 20012002 and June 30, 2000,
respectively............................................2001, respectively ................................. 11,031 10,144 9,723
Additional paid-in capital................................capital .................................................. 514,752 444,768 413,962
Treasury stock, at cost; 416,666 shares at June 30, 20012002 and June 30, 2000.................................................. (9,682) (9,682)
30, 2001
Accumulated other comprehensive income....................income (loss) ............................... (48,967) 62 8
Retained earnings (deficit).......................................................................................... 69,732 31,586
(31,124)
---------- --------------------- -----------
Total stockholders' equity..................................equity .................................................... 536,866 476,878
382,887
---------- --------------------- -----------
Total liabilities and stockholders' equity.................. $1,228,284 $1,246,265
========== ==========equity .................................... $ 1,242,995 $ 1,228,284
=========== ===========
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
23
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED JUNE 30,
-------------------------------------------------------------------------------
2002 2001 2000
1999
---------- ---------- ------------------- --------- ---------
(THOUSANDS, EXCEPT PER SHARE DATA)
REVENUES:
Well servicing............................................ $758,273 $559,492 $433,657servicing ............................................... $ 706,629 $ 758,273 $ 559,492
Contract drilling.........................................drilling ............................................ 87,077 107,639 68,428
50,613
Other.....................................................Other ........................................................ 8,858 7,350 9,812
7,547
-------- -------- ----------------- --------- ---------
Total revenues..............................................revenues ................................................. 802,564 873,262 637,732
491,817
-------- -------- ----------------- --------- ---------
COSTS AND EXPENSES:
Well servicing............................................ 493,108 399,940 324,965servicing ............................................... 489,681 500,324 408,723
Contract drilling.........................................drilling ............................................ 60,561 77,366 58,299 43,556
Depreciation, depletion and amortization..................amortization ..................... 78,265 75,147 70,972
62,074
General and administrative................................ 66,071 58,772 53,108
Bad debt expense.......................................... 1,263 1,648 5,928
Debt issuance costs....................................... 6,307
Interest..................................................administrative ................................... 59,494 60,118 51,637
Interest ..................................................... 43,332 56,560 71,930
67,401
Other expenses............................................expenses ............................................... 4,531 4,464 4,147
2,907
Corporate restructuring................................... -- -- 4,504
-------- -------- --------Foreign currency transaction loss, Argentina ................. 1,443 - -
--------- --------- ---------
Total costs and expenses....................................expenses ....................................... 737,307 773,979 665,708
570,750
-------- -------- ----------------- --------- ---------
Income (loss) before income taxes...........................taxes .............................. 65,257 99,283 (27,976) (78,933)
Income tax benefit (expense)................................ ................................... (24,074) (37,002) 7,406
25,675
-------- -------- ----------------- --------- ---------
INCOME (LOSS) BEFORE EXTRAORDINARY GAIN (LOSS).............. $ ................. 41,183 62,281 $(20,570) $(53,258)(20,570)
Extraordinary gain (loss) on retirement of debt, less applicable
income taxes of $255--2001$1,775 - 2002, $(255) - 2001 and $580--2000......$(580) - 2000 . (3,037) 429 1,611
--
-------- -------- ----------------- --------- ---------
NET INCOME (LOSS)........................................... .............................................. $ 38,146 $ 62,710 $(18,959) $(53,258)
======== ======== ========$ (18,959)
========= ========= =========
EARNINGS (LOSS) PER SHARE:
Basic--beforeSHARE :
Basic - before extraordinary gain (loss)................... ..................... $ 0.39 $ 0.63 $ (0.25) $ (1.94)
Extraordinary gain (loss) on retirement of debt, net of tax..................................................... --tax .. (0.03) - 0.02
--
-------- -------- --------
Basic--after--------- --------- ---------
Basic- after extraordinary gain...........................gain (loss) ....................... $ 0.36 $ 0.63 $ (0.23)
========= ========= =========
Diluted- before extraordinary gain (loss) .................... $ (1.94)
======== ======== ========
Diluted--before extraordinary gain........................0.38 $ 0.61 $ (0.25)
$ (1.94)
Extraordinary gain (loss) on retirement of debt, net of tax...... --tax .. (0.03) - 0.02
--
-------- -------- --------
Diluted--after--------- --------- ---------
Diluted-after extraordinary gain.........................gain (loss) ...................... $ 0.35 $ 0.61 $ (0.23)
$ (1.94)
======== ======== ================= ========= =========
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic.....................................................Basic ........................................................ 105,766 98,195 83,815
27,501
Diluted...................................................Diluted ...................................................... 107,462 102,271 83,815 27,501
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
24
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEAR ENDED JUNE 30,
------------------------------2002 2001 2000 1999
-------- -------- --------
(THOUSANDS)
NET INCOME (LOSS)........................................... $62,710 .............................................. $ 38,146 $ 62,710 $(18,959) $(53,258)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Derivative transition adjustment (See Note 8).............6) ................ - (778) -- ---
Oil and natural gas derivatives adjustment (See Note 8)...6) ...... (279) 306 -- ---
Amortization of oil and natural gas derivatives (See Note 8)......................................................6) . (367) 558 -- --
Reversal of unrealized gains on available-for-sale
securities.............................................. -- -- (1,525)-
Currency translation gain(loss)...........................gain (loss) (See Note 17) ............... (48,383) (32) (1)
9
--------------- -------- --------
COMPREHENSIVE INCOME (LOSS), NET OF TAX..................... $62,764TAX ........................ $(10,883) $ 62,764 $(18,960)
$(54,774)
=============== ======== ========
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
25
KEY ENERGY SERVICES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED JUNE 30,
---------------------------------------------------------------------------
2002 2001 2000
1999
--------- --------- -----------------
(THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... ................................... $ 38,146 $ 62,710 $ (18,959) $(53,258)
ADJUSTMENTS TO RECONCILE INCOME FROM OPERATIONS TO
NET CASH PROVIDED BY (USED IN) OPERATIONS:
Depreciation, depletion and amortization..................amortization ............ 78,265 75,147 70,972 62,074
Bad debt expense.......................................... 1,263 1,648 5,928
Amortization of deferred debt issuance costs.............. 4,317costs,
discount and premium................................. 3,005 4,947 5,919 5,216
Restructuring charge...................................... -- -- 233
Deferred income taxes.....................................taxes ............................... 23,160 34,698 (1,818) (25,675)
(Gain) loss on sale of assets.............................assets ....................... (668) 173 25
111Foreign currency transaction loss, Argentina ........ 1,443 - -
Extraordinary (gain) loss, net of tax.....................tax ............... 3,037 (429) (1,611) --
Other non-cash items...................................... -- -- 13
CHANGE IN ASSETS AND LIABILITIES NET OF EFFECTS
FROM THE ACQUISITIONS:
(Increase) decrease in accounts receivable.............. (55,076) (32,853) 9,741receivable ........ 48,907 (53,813) (31,205)
(Increase) decrease in other current assets.............assets ....... (4,410) (4,485) (5,483) (432)
Increase (decrease) in accounts payable,
accrued interest and accrued expenses.........................expenses ........... (12,180) 29,414 18,875 (17,378)
Other assets and liabilities............................liabilities ...................... 11 (5,015) (1,855)
--
--------- --------- -----------------
Net cash provided by (used in) operating activities....... 142,717activities . 178,716 143,347 34,860 (13,427)
--------- --------- -----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures--well servicing...................... (50,799)expenditures - well servicing ............... (57,857) (51,064) (26,469)
(26,776)
Capital expenditures--contract drilling...................expenditures - contract drilling ............ (19,861) (15,884) (8,282)
(1,063)
Capital expenditures--other............................... (15,437)expenditures - other ........................ (15,979) (15,802) (3,422) (3,468)
Proceeds from sale of fixed assets........................assets .................. 4,258 3,415 2,722 7,110
Notes receivable from related parties.....................parties ............... - (1,500) (2,315)
(2,835)
Cash received in acquisitions............................. -- -- 27,008
Acquisitions--well servicing..............................Acquisitions - well servicing ....................... (17,273) (2,345) -- (292,638)
Acquisitions--contract drilling...........................-
Acquisitions - contract drilling .................... (2,037) (800) -- --
Other assets and liabilities.............................. -- -- (1,992)-
--------- --------- -----------------
Net cash provided by (used in) investing activities....... (83,350)activities . (108,749) (83,980) (37,766) (294,654)
--------- --------- -----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of long-term debt and......................... (309,559) (373,998) (39,438)
Repayment of capital lease obligations............................................. (382,540) (51,077) (487,376)
Borrowings under line-of-credit........................... 30,000 12,000 328,411obligations .............. (10,182) (8,542) (11,639)
Proceeds from equity offerings, net of expenses........... --expenses ..... 42,590 - 100,571 180,441
Proceeds from long-term debt.............................. 175,210 -- 142,566debt ........................ 258,500 205,210 12,000
Proceeds paid for debt issuance costs.....................costs ............... (1,585) (4,958) -- (15,274)
Proceeds from other long-term debt........................ -- -- 150,000-
Proceeds from forward sale, net of expenses............... --expenses ......... - - 18,236 --
Proceeds from issuance of warrants........................ -- -- 7,434
Proceeds from exercise of warrants........................warrants .................. - 847 8,473 --
Proceeds from exercise of stock options...................options ............. 3,219 14,617 1,098
92
Other.....................................................Other ............................................... (298) (318) -- ---
--------- --------- -----------------
Net cash provided by (used in) financing activities.......activities . (17,315) (167,142) 89,301
306,294
--------- --------- -----------------
Effect of exchange rates on cash .................... (603) - -
Net increase (decrease) in cash...........................cash ..................... 52,049 (107,775) 86,395 (1,787)
Cash and cash equivalents at beginning of period..........period .... 2,098 109,873 23,478
25,265
--------- --------- -----------------
Cash and cash equivalents at end of period................period .......... $ 54,147 $ 2,098 $ 109,873
$ 23,478
========= ========= =================
SEE THE ACCOMPANYING NOTES WHICH ARE AN INTEGRAL PART OF THESE CONSOLIDATED
FINANCIAL STATEMENTS.
26
KEY ENERGY SERVICES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(THOUSANDS)
COMMON STOCK ACCUMULATED
-------------------------------------------- ADDITIONAL OTHER
NUMBER OF AMOUNT AT PAID-IN TREASURY COMPREHENSIVE RETAINED COMPREHENSIVE
SHARES PAR CAPITAL STOCK INCOME EARNINGS INCOME TOTAL
---------- ---------- ---------- -------- -------- -------------- ----------------- --------- --------- --------- --------- --------- ---------
BALANCE AT JUNE 30, 1998................ 18,685 $ 1,868 $119,303 $(9,682) $41,093 $ 1,525 $154,107
------- ------- -------- ------- -------- ------- --------
Reversal of unrealized gain on available
for sale securities................... -- -- -- -- -- (1,525) (1,525)
Foreign currency translation adjustment,
net of tax............................ -- -- -- -- -- 9 9
Issuance of warrants with 14% Notes..... -- -- 7,434 -- -- -- 7,434
Issuance of common stock in equity
offering, net of offering costs....... 64,245 6,425 174,016 -- -- -- 180,441
Issued to lender in lieu of fee......... 200 20 980 -- -- -- 1,000
Exercise of options..................... 15 2 92 -- -- -- 94
Other................................... 10 2 (210) -- -- -- (208)
Net income (loss)....................... -- -- -- -- (53,258) -- (53,258)
------- ------- -------- ------- -------- ------- --------
BALANCE AT JUNE 30, 1999................1999 ........ 83,155 $ 8,317 $301,615 $(9,682) $(12,165)$ 301,615 $ (9,682) $ 9 $288,094
------- ------- -------- ------- -------- ------- --------$ (12,165) $ 288,094
--------- --------- --------- --------- --------- --------- ---------
Foreign currency transition
adjustment, net of tax............................ -- -- -- -- --tax ....... - - - - (1) - (1)
Exercise of warrants....................warrants ............ 2,431 243 8,230 -- -- --- - - 8,473
Exercise of options.....................options ............. 241 24 1,074 -- -- --- - - 1,098
Conversion of 7% Debentures.............Debentures ..... 380 38 3,568 -- -- --- - - 3,606
Issuance of common stock in
equity offering, net of
offering costs.......costs................ 11,000 1,100 99,471 -- -- --- - - 100,571
Other...................................Other ........................... 3 1 4 -- -- --- - - 5
Net income (loss)....................... -- -- -- -- ............... - - - - - (18,959) -- (18,959)
------- ------- -------- ------- -------- ------- ----------------- --------- --------- --------- --------- --------- ---------
BALANCE AT JUNE 30, 2000................2000 ........ 97,210 $ 9,723 $413,962 $(9,682) $(31,124)$ 413,962 $ (9,682) $ 8 $382,887
------- ------- -------- ------- -------- ------- --------$ (31,124) $ 382,887
--------- --------- --------- --------- --------- --------- ---------
Derivative transition adjustment
(see Note 8)............................... -- -- -- -- --6) ................. - - - - (778) - (778)
Oil and natural gas derivatives
adjustment, net of tax (See
Note 8)... -- -- -- -- --6)....................... - - - - 306 - 306
Amortization of oil and natural
gas derivatives (see Note 8).............. -- -- -- -- --6) . - - - - 558 - 558
Foreign currency translation
adjustment, net of tax............................ -- -- -- -- --tax ....... - - - - (32) - (32)
Exercise of warrants....................warrants ............ 185 19 828 -- -- --- - - 847
Exercise of options.....................options ............. 3,106 308 14,309 -- -- --- - - 14,617
Conversion of 7% Debentures.............Debentures ..... 101 10 947 -- -- --- - - 957
Issuance of common stock for
acquisitions..........................acquisitions ................. 838 84 8,036 -- -- --- - - 8,120
Deferred tax benefit--compensation
expense............................... -- --benefit-
compensation expense ......... - - 7,004 -- -- --- - - 7,004
Other................................... -- --Other ........................... - - (318) -- -- --- - - (318)
Net income (loss)....................... -- -- -- -- ............... - - - - - 62,710 -- 62,710
------- ------- -------- ------- -------- ------- ----------------- --------- --------- --------- --------- --------- ---------
BALANCE AT JUNE 30, 2001................2001 ........ 101,440 $10,144 $444,768 $(9,682) $31,586$ 10,144 $ 444,768 $ (9,682) $ 62 $476,878
======= ======= ======== ======= ======== ======= ========$ 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.
27
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2002, 2001 2000 AND 19992000
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
1,4771,486 well service rigs and 1,4551,719 oilfield service vehicles as of June 30,
2001.2002. 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, 2001.2002. 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, and parts and supplies held for sale at the Company's
various retail supply stores, are valued at the lower of average cost or
market.
28
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
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...........................................rigs......................................... 25
Motor vehicles..............................................vehicles............................................ 5
Furniture and equipment..................................... 3-7equipment................................... 3 - 7
Buildings and improvements.................................. 10-40improvements................................ 10 - 40
Gas processing facilities...................................facilities................................. 10
Disposal wells.............................................. 15-30wells............................................ 15 - 30
Trucks, trailers and related equipment...................... 7-15equipment.................... 7 - 15
The components of a well service rig that generally require replacement
during the rig's life are depreciated over their estimated useful lives, which
range from three to 15 years. The basic rigs, excluding components, have
estimated useful lives from date of original manufacture ranging from 25 to 35
years. Salvage values are assigned to the rigs based on an estimate of 10%.
Effective July 1, 1998, the Company made certain changes in the estimated
useful lives of its well service rigs, increasing the lives from 17 years to
25 years. This change decreased the net loss for the twelve months ended
June 30, 1999 by approximately $3,100,000 ($0.11 per share-basic). This change
was made to better reflect the expected utilization of these assets over time,
to better provide matching of revenues and expenses and to better reflect the
industry standard in regards to estimated useful lives of workover rigs.
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 including goodwill, on a yard-by-yard
basis and compares the estimated future cash flows of each yard to the yard's
net carrying value including allocable goodwill.value. The Company would record an impairment charge, reducing
the yard's net carrying value to an estimated fair value, if the 29
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
estimated
future cash flows were less than the yard's net carrying value. Since
adoption of this statement noNo impairment
charges have been required.
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS
The Company uses derivative financial instruments, primarily commodity
option contracts to reduce the exposure of its oil and gas producing operations
to changes in the market price of natural gas and crude oil and to fix the price
for natural gas and crude oil independently of the physical sale.
29
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 8.6.
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.
30
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
ENVIRONMENTAL
The Company is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are constantly changing,
regulate the discharge of materials into the environment and may require the
Company to remove or mitigate the adverse environmental effects of the disposal
or release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are expensed. Liabilities
for expenditures of a non-capital nature are recorded when environmental
assessment and/or remediation is probable, and the costs can be reasonably
estimated.
GOODWILL NetAND 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 totaling $189.9 million and $198.6 million at June 30, 2001
and 2000, respectively, represents the cost in excess of fair value of the net
tangible and identifiableother intangible assets acquiredwith
indefinite lives. Intangible assets with lives restricted by contractual, legal,
or other means will continue to be amortized over their useful lives. Goodwill
and liabilities assumed in
purchase transactions. Goodwill is being amortized on a straight-line basis over
periods ranging from tenother intangible assets not subject to 25 years. Amortization of goodwillamortization are tested for
fiscal 2001,
2000 and 1999 was approximately $9,322,000, $9,840,000 and $9,202,000,
respectively. The carrying amount of unamortized goodwill is reviewed for
potential impairment loss wheneverannually or
30
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 may not be recoverable (see Propertyfor the year ended June 30, 2002 of $11,194,000 relates
principally to goodwill from well servicing assets acquired during the period
and Equipment above,the translation adjustment for further discussion).Argentina.
31
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 $31,052,000$32,928,000 and $30,998,000$31,052,000 at June 30, 20012002
and 2000,2001, respectively, represent debt issuance costs and are recorded net of
accumulated amortization of $13,428,000$20,348,000 and $12,143,000$13,428,000 at June 30, 20012002 and
2000,2001, 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 $5,176,000 and $4,664,000$5,176,000 for fiscal 2002, 2001 2000 and 1999,2000,
respectively. Unamortized debt issuance costs written off and included in the
determination of the extraordinary gain (loss)loss on retirement of debt, net ofbefore tax,
for fiscal 2002, totaled approximately $1,620,000$4,339,000 and the extraordinary gain
on retirement of debt, before tax for fiscal 2001.2001, totaled approximately
$2,583,000.
INCOME TAXES
The Company accounts for income taxes based upon Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"). Under
SFAS 109, deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using statutory tax
rates expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or
32
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.
31
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
The Company and its eligible subsidiaries file a consolidated U. S.
federal income tax return. Certain subsidiaries that are consolidated for
financial reporting purposes are not eligible to be included in the consolidated
U. S. federal income tax return and separate provisions for income taxes have
been determined for these entities or groups of entities.
EARNINGS PER SHARE
The Company presents earnings per share information in accordance with
the provisions of Statement of Financial Accounting Standards No. 128, "Earnings
per Share" ("SFAS 128"). Under SFAS 128, basic earnings per common share are
determined by dividing net earnings applicable to common stock by the weighted
average number of common shares actually outstanding during the year. Diluted
earnings per common share is based on the increased number of shares that would
be outstanding assuming conversion of dilutive outstanding convertible
securities using the "as if converted" method.
33
------------------------------------------
YEAR ENDED JUNE 30,
------------------------------------------------------------------------------
2002 2001 2000
1999
---------- ---------- ------------------- --------- ---------
(THOUSANDS, EXCEPT PER SHARE DATA)
BASIC EPS COMPUTATION:
NUMERATOR
Net income (loss) before extraordinary gain (loss)........ ... $ 41,183 $ 62,281 $(20,570) $(53,258)$ (20,570)
Extraordinary gain (loss), net of tax.....................tax ................ (3,037) 429 1,611
--
-------- -------- ----------------- --------- ---------
Net income (loss)......................................... .................................... $ 38,146 $ 62,710 $(18,959) $(53,258)
======== ======== ========$ (18,959)
========= ========= =========
DENOMINATOR
Weighted average common shares outstanding................outstanding ........... 105,766 98,195 83,815
27,501
-------- -------- ----------------- --------- ---------
BASIC EPS:
Before extraordinary gain (loss).......................... ..................... $ 0.39 $ 0.63 $ (0.25) $ (1.94)
Extraordinary gain (loss), net of tax..................... --tax ................ (0.03) - 0.02
--
-------- -------- ----------------- --------- ---------
Net income (loss)......................................... .................................... $ 0.36 $ 0.63 $ (0.23)
$ (1.94)
======== ======== ================= ========= =========
DILUTED EPS COMPUTATION:
NUMERATOR
Net income (loss) before extraordinary gain (loss) and
effect of dilutive securities, tax effected.............effected ....... $ 41,183 $ 62,281 $(20,570) $(53,258)$ (20,570)
Convertible securities....................................securities ............................... - 5 -- --
-------- -------- ---------
--------- --------- ---------
Net income (loss) before extraordinary gain (loss)...... $ ... 41,183 62,286 $(20,570) $(53,258)(20,570)
Extraordinary gain (loss), net of tax...................tax ............... (3,037) 429 1,611
--
-------- -------- ----------------- --------- ---------
Net income (loss)....................................... .................................... $ 38,146 $ 62,715 $(18,959) $(53,258)
======== ======== ========
32
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
YEAR ENDED JUNE 30,
------------------------------------
2001 2000 1999
---------- ---------- ----------
(THOUSANDS, EXCEPT PER SHARE DATA)
$ (18,959)
========= ========= =========
DENOMINATOR
Weighted average common shares outstanding................outstanding ........... 105,766 98,195 83,815
27,501
Warrants..................................................Warrants ........................................... 402 205 -- ---
Stock options.............................................options ...................................... 1,294 3,853 -- ---
7% Convertible Debentures.................................Debentures .......................... - 18 -- --
-------- -------- ---------
--------- --------- ---------
107,462 102,271 83,815
27,501--------- --------- ---------
DILUTED EPS:
Before extraordinary gain (loss).......................... ..................... $ 0.38 $ 0.61 $ (0.25) $ (1.94)
Extraordinary gain (loss), net of tax..................... --tax ................ (0.03) - 0.02
--
-------- -------- ----------------- --------- ---------
Net income (loss)......................................... .................................... $ 0.35 $ 0.61 $ (0.23)
$ (1.94)
======== ======== ================= ========= =========
The diluted earnings per share calculation for the yearyears ended June 30,
2002 and 2001 excludes the effect of the potential exercise of 360,000 stock options of
1,177,000 and 360,000, respectively, and the potential conversion of the
Company's 5% Convertible Subordinated Notes because the effects of such
instruments on earnings per share would be anti-dilutive.
The diluted earnings per share calculation for the yearsyear ended June 30,
2000 and 1999 excludes the effect of the potential conversion of all of the Company's
then outstanding convertible debt and the potential exercise of all of the
Company's then outstanding warrants and stock options because the effects of
such instruments on loss per share would be anti-dilutive.
34
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 whowhich represented 10% or more of consolidated
revenues for the fiscal yearyears ended June 30, 2001 2000 or 1999.
33
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)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 108
the pro forma information required under SFAS 123.
FOREIGN CURRENCY GAINS AND LOSSES
The local currency is the functional currency for all of the Company's
foreign operations (Argentinain Argentina and Canada).Canada. The cumulative translation gains
and losses, resulting from translating each foreign subsidiary's financial
statements from the functional currency to U.S. dollars, is included in other
comprehensive income and accumulated in stockholders' equity until a partial
or complete sale or liquidation of the Company's net investment in the
foreign entity.
CASH AND CASH EQUIVALENTS
The Company considers all unrestricted highly liquid investments with
less than a three-month maturity when purchased, as cash equivalents.
35
RECLASSIFICATIONS
Certain reclassifications have been made to the fiscal 2000 and 1999
consolidated
financial statements for the years ended June 30, 2001 and 2000 to conform to
the fiscal 2001year end June 30, 2002 presentation. The reclassifications consist
primarily of reclassifying oilcertain items from general and natural gas
productions revenues andadministrative
expense to direct expenses.
Oil and natural gas production revenues and
related expenses have been reclassified to other revenues and other expenses
because the Company does not believe this business segment is material to the
Company's consolidated financial statements.
2. RESTRUCTURING CHARGE
In response to an industry downturn caused by historically low oil and gas
prices and the resulting slowdown in business, on December 7, 1998, the Company
announced a company-wide restructuring plan to reduce operating costs beyond
those achieved through the Company's consolidation efforts. The plan involved a
reduction in the size of management and on-site work force, salary reductions
averaging 21% for senior management, the combination of previously separate
operating divisions and the elimination of redundant overhead and facilities.
The restructuring plan resulted in pretax charges to
34
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
2. RESTRUCTURING CHARGE (CONTINUED)
earnings of approximately $6.7 million in the second quarter ending
December 31, 1998 and $1.5 million in the third quarter ending March 31, 1999.
However, due to an increase in oil and gas prices beginning during the quarter
ended March 31,1999, the Company amended its restructuring plan to decrease the
number of planned employee terminations. Increased demand for the Company's
services made such terminations unnecessary and would have, in management's
opinion, restricted the Company's ability to provide services to its customers.
Consequently, the Company did not utilize approximately $3.7 million of the
pretax charges. Essentially all of the unutilized portion of the restructuring
charge was reversed in the fourth quarter ending June 30, 1999 resulting in a
total pretax charge for the fiscal year ended June 30, 1999 of approximately
$4.5 million. The charges included severance payments and other termination
benefits for approximately 97 employees, lease commitments related to closed
facilities and environmental studies performed on closed leased yard locations.
The Company completed the plan at June 30, 2000. There remained
approximately $180,000 for COBRA benefits to terminated employees and $53,000
for contractual payments to an employee at June 30, 1999. The major components
of the restructuring charge and costs incurred through June 30, 1999 were as
follows:
RESTRUCTURING COST INCURRED BALANCE AS OF
DESCRIPTION CHARGE THROUGH JUNE 30, 1999 JUNE 30, 1999
----------- ------------- ---------------------- --------------
(IN THOUSANDS)
Severance/employee costs.......... $4,457 $(4,224) $233
Lease commitments................. 27 (27) --
Environmental clean-up............ 20 (20) --
------ ------- ----
Total............................. $4,504 $(4,271) $233
====== ======= ====
3. BUSINESS AND PROPERTY ACQUISITIONS
ACQUISITIONS COMPLETED IN FISCAL 2001 AND 2000
There were no acquisitions completed by the Company duringDuring fiscal 2000.
During fiscal2002 and 2001, the Company completed several small
acquisitions for a total consideration of $44,378,000 and $11,965,000,
respectively, which was paid usingconsisted of a combination of cash, notes and shares of
the Company's common stock. ThroughNone of the acquisitions completed in fiscal 2002
were individually material, thus the pro forma effect of these acquisitions
the
Company acquired 34 well service rigs, 8 trucking vehicles, ancillary equipment
and five salt water disposal facilities.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. DAWSON PRODUCTIONS SERVICES, INC.
In September 1998,There were no acquisitions completed
by the Company completed the acquisition of all of the
capital stock of Dawson Production Services, Inc. (Dawson) for an aggregate
consideration of approximately $382.6 million, including approximately
$207.1 million of cash paid for the Dawson stock and for transactional fees and
approximately $175.5 million of net liabilities assumed.
35
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999in fiscal 2000.
3. BUSINESS AND PROPERTY ACQUISITIONS (CONTINUED)
Expenditures for the Dawson acquisition, including acquisition costs, less
cash acquired were as follows (in thousands):
Fair value of assets acquired, including goodwill........... $409,722
Liabilities assumed......................................... (199,439)
Liabilities for employee termination costs and lease
termination costs......................................... (3,162)
--------
Cash paid, including acquisition related expenditures and
the cost of Dawson common stock previously held........... 207,121
Less: Cash acquired......................................... (27,008)
--------
Net cash used for the acquisition........................... $180,113
========
At the time of the closing, Dawson owned approximately 527 well service
rigs, 200 oilfield trucks, and 21 production testing units in South Texas and
the Gulf Coast, East Texas and Louisiana, the Permian Basin of West Texas and
New Mexico, the Anadarko Basin of Texas and Oklahoma, California, and in the
inland waters of the Gulf of Mexico.
In connection with the Dawson acquisition, the Company recognized
liabilities for the estimated costs to involuntarily terminate employees of
Dawson and to exit certain activities of Dawson, primarily Dawson's lease
liability for its corporate offices. As of June 30, 1999, the Company had
completed its severance plan, terminating 44 former Dawson employees. At
June 30, 1999, the Company had $592,000 accrued, representing the estimated
lease termination costs of Dawson's former corporate offices.
OTHER FISCAL 1999 ACQUISITIONS
In addition to its acquisition of Dawson, the Company acquired the assets
and/or capital stock of six well servicing and contract drilling businesses
during fiscal 1999, increasing its rig and truck fleet by a total of
approximately 93 well service rigs, 4 drilling rigs and 185 oilfield trucks (and
related equipment) for an aggregate purchase price of approximately
$93.7 million in cash. Each of the acquisitions was accounted for using the
purchase method and the results of the operations, generated from the acquired
assets, are included in the Company's results of operations as of the completion
date of each acquisition.
PRO FORMA RESULTS OF OPERATIONS--(UNAUDITED)
The following unaudited pro forma results of operations have been prepared
as though the Dawson acquisition had been acquired on July 1, 1998 with
adjustments to record specifically identifiable decreases in direct costs and
general and administrative expenses related to the termination of individual
employees. Pro forma amounts are not necessarily indicative of the results that
may be reported in the future.
YEAR ENDED
JUNE 30, 1999
----------------------------------
(THOUSANDS, EXCEPT PER SHARE DATA)
Revenues......................................... $524,924
Net income (loss)................................ (58,211)
Basic earnings (loss) per share.................. (2.12)
36
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
4. COMMITMENTS AND CONTINGENCIES
Various suits and claims arising in the ordinary course of business are
pending against the Company. Management does not believe that the disposition of
any of these items will result in a material adverse impact to the consolidated
financial position, results of operations or cash flows of the Company.
In order to retain qualified senior management, the Company enters
into employment agreements with its executive officers. These employment
agreements run for periods ranging from three to five years, but can be
automatically extended on a yearly basis unless terminated by the Company or
the executive officer. In addition to providing a base salary for each
executive officer, the employment agreements provide for severance payments
for each executive officer varying from 1three to 3five years of the executive
officer's base salary. At June 30, 20012002 the annual base salaries for the
executive officers covered under such employment agreements totaled
$1,125,000.$1,165,000. The Company also enters into employment agreements with other key
employees as it deems necessary in order to retain qualified personnel.
5.4. LONG-TERM DEBT
The components of the Company's long-term debt are as follows:
36
JUNE 30,
---------------------------------------------
2002 2001 2000
-------- --------
(THOUSANDS)
Senior Credit Facility Revolving Loans (i) Revolving Loans............................................. $ - $ 2,000 $ 93,000
Tranche A Term Loan................................... -- 22,987
Tranche B Term Loan................................... -- 175,961
8 3/8% Senior Notes Due 2008 (ii)....................... ............... 276,433 175,000 --
14% Senior Subordinated Notes Due 2009 (iii)............ .... 94,257 134,466 143,650
5% Convertible Subordinated Notes Due 2004 (iv)........... 49,951 158,426
205,810
Dawson 9 3/8% Senior Notes Due 2007 (v)................. 246 1,106
7% Convertible Subordinated Debentures Due 2003 (vi).... -- 1,000
Capital Leases..........................................Leases .................................. 22,829 22,964 21,911
Other notes payable..................................... 805 1,175payable ............................. 140 1,051
-------- --------
443,610 493,907 666,600
Less current portion....................................portion ............................ 7,674 7,946 14,655
-------- --------
Total long-term debt....................................debt ............................ $435,936 $485,961 $651,945
======== ========
(I)(i) SENIOR CREDIT FACILITY
At June 30, 2001,During the fiscal 2002, the Company's senior credit facility (the
"Senior"Prior Senior Credit Facility") consisted of a $125$100 million revolving credit
facility. In addition, up to $20$30 million of letters of credit cancould be issued
under the Prior Senior Credit Facility, but any outstanding letters of credit
reducesreduced borrowing availability under the revolver. The commitment to make revolving loans reduced to
$100Company drew down
approximately $43 million on 37
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
5. LONG-TERM DEBT (CONTINUED)
SeptemberJanuary 14, 2001 and will reduce2002 in order to $75 million on September 14,redeem the 14%
Senior Subordinated Notes. The funds were repaid with the issuance of
additional 8 3/8% Notes in March 2002.
The revolving commitment will terminate on September 14, 2003, and all the revolving
loans must be paid on or before that date.
The revolving loans bearbore interest at rates based upon, at the
Company's option, either the prime rate plus a variable margin ranging fromof 0.75% to
2.00% or a Eurodollar rate plus a variable margin ranging fromof 2.25% to 3.50%, in each case
depending upon the ratio of the Company's total debt (less cash on hand over
$5 million) to the Company's trailing 12-month EBITDA, as adjusted.. The
Company payspaid 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%.
The Senior Credit Facility contains various financial covenants, including:
(i) consolidated debt-to-capitalization ratio at generally decreasing levels
varying between 79% and 65%, (ii) consolidated interest coverage ratio at
generally increasing levels varying between 2.00-to-1.00 and 3.50-to-1.00,
(iii) consolidated senior leverage ratio at generally decreasing levels varying
between 2.50-to-1.00 and 2.00-to-1.00, and (iv) trailing 12-month EBITDA, as
adjusted, at generally increasing levels varying between $50 million and
$150 million. In addition, the Company must maintain a consolidated fixed charge
coverage ratio at generally decreasing levels varying between 1.25-to-1.00 and
1.00 to 1.00. The covenants for consolidated senior leverage ratio and
consolidated interest coverage ratio are not imposed until the quarter ending
March 31, 2001, and the covenant levels for consolidated debt-to-capitalization
and trailing 12-month EBITDA, as adjusted, will remain fixed at 79% and
$50 million, respectively, for the same period. The Company is also required to
maintain a consolidated liquidity level of at least $30 million.
The 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
sell assets, to make dividends, purchases of our stock or subordinated debt, to
make capital expenditures in excess of levels ranging from $37.5 million in
fiscal 1999 to $65 million in fiscal 2004, or to make investments, loans and
advances or changes to debt instruments and organizational documents. The
Company will not be permitted to make acquisitions unless (i) its consolidated
debt to capitalization ratio is not more than 60% or (ii) its consolidated debt
to capitalization ratio is not increased and the acquisition is funded solely
with capital stock. The Company must also maintain consolidated net worth not
less than, $195 million plus (i) 75% of consolidated net income for each fiscal
quarter beginning with the period ending December 31, 1998, (ii) 75% of the net
cash proceeds from issuance of capital stock after September 14, 1998 and
(iii) 75% of the increase in consolidated net worth resulting from the
conversion of the 5% Convertible Subordinated Notes or other convertible debt
issued after September 14, 1998. All obligations under the Senior Credit
Facility are guaranteed by most of the Company's subsidiaries and are secured by
substantially all the Company's assets, including the Company's accounts
receivable, inventory and equipment.37
During fiscal 2001, a portion of the net proceeds from the 2000
Equity Offering (see Note 10)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%
38
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
5. LONG-TERM DEBT (CONTINUED) 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, 2001,2002, there was approximately $2,000,000no balance outstanding under the revolving
loans. Additionally, the Company had outstanding letters of credit of
$11,995,000$27,963,000 and $15,132,000$11,995,000 as of June 30, 2002 and 2001, and 2000, respectively, under
the senior credit facility related to its workers compensation insurance.
(II)(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, ranking equally with the
Company's senior unsecured indebtedness.obligations. The 8 3/8% Senior Notes
are effectively subordinated to Key's secured indebtedness which includes
borrowings under the Senior Credit Facility and the Dawson 9 3/8% Senior Notes.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, 2001, $175,000,0002002, $275,000,000 principal amount of the 8 3/8% Senior
Notes remained outstanding. The 8 3/8% Senior Notes payrequire semi-annual
interest semi-annuallypayments on March 1 and September 1 of each year. (III)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"(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 common stockthe 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 $148.6 million$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").
38
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 maywas 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 at 114% of par,
plus accrued interest. On June 11,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, leaving
$139,687,000interest. 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 outstanding as of June 30, 2001.the 14% Senior Subordinated Notes
at a price of 114% of the principal amount plus accrued interest. This
transaction resulted in an extraordinary loss before taxes of approximately
$8,468,000. Also, during fiscal 2002, the Company purchased and canceled
$6,784,000 principal amount of the 14% Senior Subordinated Notes at a price of
116% of the principal amount plus accrued interest. These transactions resulted
in extraordinary losses before taxes of approximately $1,821,000.
The Unit Warrants have separated from the 14% Senior Subordinated Notes
and became exercisable on January 25, 2000. On the date of issuance, the value
of the Unit Warrants was estimated
39
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
5. LONG-TERM DEBT (CONTINUED) 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 Current
Senior Credit Facility the Dawson 9 3/8% Senior Notes and the 8 3/8% Senior Notes.
In the event of a change in control of the Company, as defined in the
indenture under which the 14% Senior Subordinated Notes were issued, each holder
of 14% Senior Subordinated Notes will have the right, at the holder's option, to
require the Company to repurchase all or any part of the holder's 14% Senior
Subordinated Notes, within 60 days of such event, at a price equal to 100% of
the principal amount thereof, together with accrued and unpaid interest thereon.
During fiscal 2001, the Company repurchased (and cancelled) $10,313,000
principal amount of the 14% Senior Subordinated Notes and paid a premium of
approximately $1,444,000. At June 30, 2001, $139,687,0002002, $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,
beginning July 15, 1999.year. Interest payments
of approximately $10,500,000 was paid$9,778,000 and $6,825,000 were made on July 15, 20002001 and
January 15, 2001.2002, respectively. As of June 30, 2001, 62,5002002, 63,500 Unit Warrants had
been exercised, producing approximately $4,173,000 of proceeds to the Company
and leaving 87,50086,500 Unit Warrants outstanding.
(IV)(iv) 5% CONVERTIBLE SUBORDINATED NOTES
In late September and early October 1997, the Company completed a
private placement of $216 million$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, the Dawson
9 3/8% Senior 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 cancelled)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 $158,426,000$49,951,000 principal amount of the 5% Convertible Subordinated Notes
outstanding at June 30, 2001.2002. These repurchases resulted in an after tax gainextraordinary
gains before taxes of approximately $3.2 million.$5,633,000. Interest on the 5%
Convertible Subordinated Notes is payable on March 15 and September 15. Interest of approximately $4,890,000 was paid on
September 15 2000 and $4,815,000 was paid on March 15, 2001, respectively.
(V) DAWSON 9 3/8% SENIOR NOTES
As a result of the Dawson acquisition (see Note 3), the Company, its
subsidiaries and U.S. Trust Company of Texas, N.A., as trustee ("U.S. Trust"),
entered into a Supplemental Indenture dated
40
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
5. LONG-TERM DEBT (CONTINUED)
September 21, 1998 (the "Supplemental Indenture"), pursuant to which the Company
assumed the obligations of Dawson under the Indenture dated February 20, 1997
(the "Dawson Indenture") between Dawson and U.S. Trust. The senior notes due
2007 (the "Dawson 9 3/8% Senior Notes") issued pursuant to the Dawson Indenture
were equally and ratably secured with the obligations under the Senior Credit
Facility. As a result of a mandatory tender offer made in connection with the
Dawson acquisition and subsequent repurchases, only $1,106,000 principal amount
of Dawson 9 3/8% Senior Notes remained outstanding at June 30, 2000.
During fiscal 2001, the Company repurchased $860,000 principal amount of the
Dawson 9 3/8% Senior Notes, leaving $246,000 principal amount outstanding as of
June 30, 2001. Interest on the Dawson 9 3/8% Senior Notes is payable on
February 1 and August 1 of
each year. Interest of approximately $52,000$3,027,000 and approximately $14,000$1,259,000 was paid on
August 1, 2000September 15, 2001 and February 1, 2001,March 15, 2002, respectively.
(vi) 7% CONVERTIBLE SUBORDINATED DEBENTURES
In July 1996, the Company completed a private placement of $52,000,000
principal amount of 7% Convertible Subordinated Debentures due 2003 (the "7%
Convertible Subordinated Debentures"). During the quarter ended September 30,
2000, $985,000 principal amount of the 7% Convertible Subordinated Debentures
were surrendered for conversion by the holders thereof and 101,025 shares of
common stock were issued on September 1, 2000 in connection with the conversion.
On September 1, 2000, the remaining $15,000 principal amount of the outstanding
7% Convertible Subordinated Debentures was redeemed at 103% of the principal
amount plus accrued interest, leaving none outstanding. Interest on the 7%
Convertible Subordinated Debentures was payable on January 1 and July 1 of each
year. Interest of approximately $35,000 was paid on July 1, 2000.39
CAPITALIZED DEBT ISSUANCE COSTS, REPAYMENT SCHEDULE AND INTEREST EXPENSE
The Company capitalized a total of approximately $4,958,000$1,877,000 and
$16,370,000$4,958,000 in fees and costs in connection with its various financings during
fiscal 20012002 and 19992001, respectively. The Company did not incureincur any fees or costs
in connection with financing activities in fiscal 2000.
Presented below is a schedule of the repayment requirements of
long-term debt (excluding the discount on the 14% Senior Subordinated Notes and
the premium on the 8 3/8% Senior Notes) for each of the next five years and
thereafter as of June 30, 2001:2002:
PRINCIPAL
FISCAL YEAR ENDEDENDING JUNE 30, AMOUNT
-------------------------- --------------
(IN THOUSANDS)(THOUSANDS)
2002........................................................2003........................................................................ $ 7,946
2003........................................................ 7,912
2004........................................................ 9,911
2005........................................................ 158,426
2006........................................................ --
Thereafter.................................................. 309,712
--------
$493,907
========7,674
2004........................................................................ 7,679
2005........................................................................ 57,567
2006........................................................................ -
2007........................................................................ -
Thereafter.................................................................. 372,500
-------------
$445,420
=============
41
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
5. LONG-TERM DEBT (CONTINUED)
The Company's interest expense for the years ended June 30, 2002, 2001,
2000, and 19992000 consisted of the following:
2002 2001 2000
1999
-------- -------- --------
(IN THOUSANDS)----------- ------------ ----------
(THOUSANDS)
Cash payments for interest............................interest...................... $42,085 $51,524 $61,956 $52,397
Commitment and agency fees paid.......................paid................ 1,183 1,203 1,139 527
Accretion of discount and premium on notes........................notes...... 424 739 743 552
Amortization of debt issuance costs...................costs............. 2,581 3,578 5,176 4,664
Net change in accrued interest........................interest.................. (1,275) 146 2,916
9,261
Other.................................................Capitalized interest............................ (1,666) (630) -- --
------- ------- --------
----------- ------------ ----------
$43,332 $56,560 $71,930
$67,401
======= ======= ================== ============ ==========
6. DEBT ISSUANCE COSTS
During fiscal 1999, the Company recorded an expense item of $6,307,000 which
represented the write-off of debt issuance costs. The debt issuance costs were
associated with a bridge loan incurred in connection with the Dawson
acquisition, which was subsequently paid primarily with the proceeds from the
Company's private placement of 14% Senior Subordinated Notes (see Note 5).
During fiscal 2000, the Company expensed $338,000 of debt issuance costs related
to the conversion of 7% Convertible Subordinated Debentures and other
prepayments of debt.
7.5. 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, 20012002 and 2000.2001. FASB
Statement No. 107, "Disclosures about Fair Value of Financial Instruments",Instruments,"
defines the fair value of a financial instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties.
40
2002 2001
2000
------------------- ------------------------------------------- -------------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- -------- -------- --------
Financial Assets:
Cash and cash equivalents...............equivalents ......... $ 54,147 $ 54,147 $ 2,098 $ 2,098
$109,873 $109,873
Accounts receivable, net................net .......... 117,907 117,907 177,016 177,016
123,203 123,203
Notes receivable--related parties.......receivable - related parties 274 274 6,050 6,600
5,150 5,150
Commodity option contracts..............contracts ........ 246 246 1,035 1,035 -- --
Financial Liabilities:
Accounts payable........................payable .................. 24,625 24,625 42,544 42,544
34,091 34,091
Commodity option contracts..............contracts ........ - - 344 344
-- 778
Long-term debtdebt:
Senior Credit Facility................Facility .......... - - 2,000 2,000 291,948 291,948
8 3/8% Senior Notes...................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.....Notes 49,951 46,942 158,426 141,989
205,810 160,532
7% Convertible Subordinated
Debentures.......................... -- -- 1,000 1,130
14% Senior Subordinated Notes......... 134,466 153,498 143,650 162,325
Dawson 9 3/8% Senior Notes............ 246 246 1,106 1,029
Capital lease liabilities.............liabilities ....... 22,829 22,829 22,964 22,964
21,911 21,911
Other debt............................ 805 805 1,175 1,175debt ...................... 140 140 1,051 1,051
42
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
7. FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED)
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: For fiscal 2001, under SFAS 133, the carrying amount of the
commodity option contracts approximate fair value. For fiscal
2000, the carrying value is comprised of the unamortized premiums paid for the
option contracts. The fair value of the
commodity option contracts is estimated using the discounted forward prices of
each optionsoption'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,
20012002 and 2000,2001, and the carrying amounts outstanding under the Company's senior
credit facility.
8.6. DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instruments to manage well
defined commodity price risks. The Company is exposed to credit losses in the
event of nonperformance by the counter-parties to its commodity hedges. The
Company only deals with reputable financial institutions as counter-parties and
anticipates that such counter-parties will be able to fully satisfy their
obligations under the contracts. The Company does not obtain collateral or other
security to support financial instruments subject to credit risk but monitors
the credit standing of the counter-parties.
The Company periodically hedges a portion of its oil and natural gas
production through collar and option agreements. The purpose of the hedges is to
provide a measure of stability in the volatile environment of oil and natural
gas prices and to manage exposure to commodity price risk under existing sales
commitments. The Company's risk
41
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 2002.2002 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.
43
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
8. DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED)
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 2001. It is estimated that the remaining
$258,000 of this transition adjustment will be recognized in earnings over the
next fiscal year.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. During fiscal 2001,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 increase of $999,000decrease in derivative assets net of derivative liabilities of
which$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 represented ineffectivenessfor fiscal 2002 and was
credited to earnings.2001, respectively.
EMBEDDED DERIVATIVES. The Company is party to a volumetric production
payment that meets the definition of an embedded derivative under SFAS 133.
Effective July 1, 2000, the Company determined and documented that the
volumetric production payment is excluded from the scope of SFAS 133 under the
normal purchases/sales exclusion as set forth in SFAS 138.
For fiscal 2000, and 1999, 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 and
increased oil and natural gas revenues for the year ended June 30, 1999 by
$158,500.$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, 20012002 and
2000:2001:
42
MONTHLY INCOME STRIKE PRICE
------------------------------------ PER BBL/MMBTU
OIL NATURAL 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 Collars.................Collar.......... 5,000 --- Mar 2001 - Feb2001-Feb 2002 $19.70 $23.70 $(115,000)($115,000)
Oil Put.....................Put............. 5,000 --- Mar 20022002-Feb 2003 $22.00 - Feb 2003 22.00 -- 141,000
Natural$141,000
Gas Collars......... --Collar.......... - 40,000 Mar 2001 - Feb2001-Feb 2002 2.40$2.40 $ 2.91 (229,000)
Natural($229,000)
Gas Put............. --- 75,000 Mar 20022002-Feb 2003 $3.00 - Feb 2003 3.00 -- 894,000
At June 30, 2000
Oil Collars................. 4,000 -- May 2000 - Feb 2001 $22.20 $26.50 $(118,000)
5,000 -- Mar 2001 - Feb 2002 19.70 23.70 (140,000)
Natural Gas Collars......... -- 30,000 May 2000 - Feb 2001 2.60 3.19 (272,000)
-- 40,000 Mar 2001 - Feb 2002 2.40 2.91 (248,000)$894,000
(The strike prices for the oil optionscollars 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 44
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
8. DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED)
Waha spot price; the strike price for
the natural gas put is based on the Inside FERC-El Paso Permian spot price.)
9.7. OTHER ACCRUED LIABILITIES
Other accrued liabilities consist of the following:
JUNE 30,
------------------------------------------------------
2002 2001
2000
-------- ------------------------ ---------------
(THOUSANDS)
Accrued payroll, taxes and employee benefits..............benefits............. $28,479 $31,242 $15,261
State sales, use and other taxes..........................taxes......................... 2,344 5,825 2,465
Oil and natural gas revenue distribution..........................distribution................. 1,271 1,606
1,714
Other.....................................................Other ................................................... 17,371 10,250
6,958
------- -------
Total.....................................................---------------- ---------------
Total.................................................... $49,465 $48,923
$26,398
======= ======================= ===============
10.Other non-current accrued expenses consist primarily of workers
compensation reserves.
8. STOCKHOLDERS' EQUITY
EQUITY OFFERINGS
On December 19, 2001, the Company closed a public offering of
5,400,000 shares of common stock, yielding approximately $43.2 million, or
$8.00 per share, to the Company, (the "Equity Offering"). Net proceeds from
the Equity Offering of approximately $42.6 million were used to temporarily
reduce amounts outstanding under the Company's revolving line of credit. The
net proceeds of the Equity Offering were ultimately used in January 2002 to
redeem a portion of the Company's 14% Senior Subordinated Notes fully
utilizing the Company's equity "claw-back" rights for up to 35% of the
original $150 million issued.
On June 30, 2000, the Company closed thea public offering of 11,000,000
shares of common stock at $9.625 per share, or approximately $106 million (the
"Equity"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.
On May 7, 1999, the Company closed the public offering of 55,300,000 shares
of common stock (300,000 shares of which were sold pursuant to the underwriters'
over-allotment option discussed below) at $3.00 per share, or $166 million (the
"Prior Public Offering"). Concurrently therewith, the Company closed the
offering of 3,508,772 shares of common stock at $2.85 per share, or $10 million
(the "Prior Concurrent Offering" and together with the Prior Public Offering,
the "Prior Equity Offerings"). In addition, on June 7, 1999, the underwriters of
the Prior Public Offering exercised an over-allotment option to purchase an
additional 5,436,000 million shares to cover over-allotments. Net proceeds from
the Prior Equity Offerings of approximately $180.4 million were used to repay a
portion of the Company's term loan borrowings under its senior credit facility.43
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").
45
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
10. STOCKHOLDERS' EQUITY (CONTINUED)
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 offeringofferings discussed above, as of June 30, 2001,2002, the number of
shares of the Company's common stock that may be covered by Incentive Awards has
increased to approximately 10.111.0 million.
Any shares of the Company's common stock that are issued and are
forfeited or are subject to Incentive Awards under the 1997 Incentive Plan that
expire or terminate for any reason will remain available for issuance with
respect to the granting of Incentive Awards during the term of the 1997
Incentive Plan, except as may otherwise be provided by applicable law. Shares of
the Company's common stock issued under the 1997 Incentive Plan may be either
newly issued or treasury shares, including shares of the Company's common stock
that the Company receives in connection with the exercise of an Incentive Award.
The number and kind of securities that may be issued under the 1997 Incentive
Plan and pursuant to then outstanding Incentive Awards are subject to
adjustments to prevent enlargement or dilution of rights resulting from stock
dividends, stock splits, recapitalizations, reorganization or similar
transactions.
The maximum number of shares of the Company's common stock subject to
Incentive Awards that may be granted or that may vest, as applicable, to any one
Covered Employee (defined below) during any calendar year shall be 500,000
shares, subject to adjustment under the provisions of the 1997 Incentive Plan.
The maximum aggregate cash payout subject to Incentive Awards
(including SARs, performance units and performance shares payable in cash, or
other stock-based awards payable in cash) that may be granted to any one Covered
Employee during any calendar year is $2,500,000. For purposes of the 1997
Incentive Plan, "Covered Employees" means a named executive officer who is one
of the group covered employees as defined in Section 162(m) of the Code and the
regulation promulgated thereunder (i.e., generally the chief executive officer
and the other four most highly compensated executive officers for a given year.)
4644
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
10. STOCKHOLDERS' EQUITY (CONTINUED)
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 ENDINGENDED JUNE 30,
-----------------------------------------------------------------------------------------------------------------------------------------------
2002 2001 2000
1999
------------------- ------------------- ----------------------------------------- --------------------------- ---------------------------
WEIGHTED WEIGHTEDWEIGHTED- WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
-------- -------- -------- -------- -------- ------------------ ---------- ----------- -------------- ------------- -----------
Outstanding--beginningOutstanding:
Beginning of fiscal year............................year........... 8,703 $7.49 9,470 $6.37 6,920 $5.55
2,292 $10.33
Granted.........................Granted............................ 1,988 8.16 2,533 8.08 3,688 8.61
5,443 4.32
Exercised.......................Exercised.......................... (659) 4.53 (3,107) 4.70 (241) 4.56
(15) 6.36
Forfeited.......................Forfeited.......................... (24) 4.86 (193) 4.92 (897) 9.80
(800) 10.87
------- ----- -----
Outstanding--end----------- --------- ----------
End of fiscal year...year................. 10,008 7.80 8,703 7.49 9,470 6.37
6,920 5.55
======= ===== =====
Exercisable--end=========== ========= ==========
Exercisable - end of fiscal year... 4,360year..... 6,273 5,820 4,370
1,020
======= ===== ================ ========= ==========
STOCK INCENTIVE PLANS
The foregoing stock option activity summary reflects that effective as of
September 4, 1998, the Committee authorized the cancellation and reissue of
stock options for employees that were not executive officers for the purpose of
changing the exercise price and vesting schedule of such options. A total of
473,556 stock options were cancelled, with a weighted average price of
approximately $13.09 per share, and reissued with an exercise price of $7.125
per share. The vesting of the new options is ratable over a three-year period
from the date of grant.
The following table summarizes information about the stock options
outstanding at June 30, 20012002 (shares in thousands):
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------------------------- -------------------------------------------------------------------------------------- -------------------------------
WEIGHTED NUMBER OF SHARES WEIGHTED-AVERAGE WEIGHTED-WEIGHTED NUMBER OF WEIGHTED
AVERAGE SHARES WEIGHTED-
OUTSTANDING AT REMAINING CONTRACTUAL AVERAGE OUTSTANDING ATSHARES AVERAGE EXERCISE
RANGE OF EXERCISE REMAINING OUTSTANDING AT EXERCISE OUTSTANDING AT EXERCISE
PRICES CONTRACTUAL LIFE JUNE 30, 2001 LIFE EXERCISE2002 PRICE JUNE 30, 20012002 PRICE
------------------------- ---------------------- ----------------- ----------------- ----------- ---------------- --------------------- -------------- ---------------- ---------------------------
$3.00 - $6.8125 1,921 6.49 $3.65 1,802 $3.51
$7.125$7.13 5.65 2,052 $ 4.63 1,602 $ 4.82
7.25 - $7.4375 1,252 7.828.13 8.75 1,997 7.86 299 7.71
8.25 - 8.31 7.71 2,080 8.25 1,857 8.26
8.35 - 8.50 7.25 439 7.13
$8.1252,225 8.48 1,229 8.47
8.88 - $8.3125 2,135 8.67 8.25 176 8.31
$8.50 - $13.25 3,395 7.69 9.27 1,943 9.6813.25 6.65 1,677 10.12 1,286 10.39
47
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
10. STOCKHOLDERS' EQUITY (CONTINUED)
The Company applies the intrinsic value method of APB 25 in accounting
for its employee stock incentive plans. Accordingly, no compensation expense has
been recognized for any stock options issued under the employee plans. Had
compensation expense for stock options granted to employees been recognized
based on the fair value at the grant dates, using the methodology prescribed by
SFAS 123, the Company's net income (loss) and earnings (loss) per share would
have been reduced to pro forma amounts indicated below:
45
FISCAL YEAR ENDED JUNE 30,
----------------------------------------
2002 2001 2000
1999
-------- -------- -------------------- ------------ ------------
(THOUSANDS, EXCEPT PER SHARE AMOUNTS)DATA)
Net income (loss):
As reported..................................reported................................... $38,146 $62,710 $(18,959)
$(53,258)
Pro forma....................................forma..................................... 26,320 52,338 (25,684) (57,057)
Basic earnings per share of common stock:
As reported..................................reported................................... $ 0.36 $ 0.63 $ (0.23)
$ (1.94)
Pro forma....................................forma..................................... 0.25 0.53 (0.31) (2.07)
Diluted earnings per share of common stock:
As reported..................................reported................................... $ 0.35 $ 0.61 $ (0.23)
$ (1.94)
Pro forma....................................forma..................................... 0.24 0.51 (0.31) (2.07)
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
2000 and 19992000 was approximately $7,700,000, $11,217,000 $19,541,000 and $15,695,000,$19,541,000,
respectively. The fair value of each stock option grant was estimated on the
date of grant using the Black-Sholes option-pricing model, based on the
following weighted-average assumptions.
11. INCOME TAXES
FISCAL YEAR OF GRANT
----------------------------------------------------------------------
2002 2001 2000
1999
-------- -------- ------------------ --------- ---------
Risk-free interest rate...........................rate.............................. 3.35% 4.30% 6.40% 5.09%
Expected life of options..........................options............................. 5 years 5 years 5 years
Expected volatility of the Company's stock price...........................................price..... 50% 59% 67%
98%
Expected dividends................................ Nonedividends................................... none none none
48
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
11.9. INCOME TAXES (CONTINUED)
Components of income tax expense (benefit) are as follows:
FISCAL YEAR ENDED JUNE 30,
------------------------------------------------------------------------------
2002 2001 2000
1999
-------- --------- ------------------ ----------- -----------
(THOUSANDS)
Federal and State:
Current.....................................Current ............................... $ 914 $ 2,304 $(5,588)
$ --
Deferred
U.S.......................................U.S ................................... 23,160 34,698 (1,818)
(25,560)
Foreign................................... -- -- (115)
------- ------- --------Foreign ............................... - - -
---------- ----------- -----------
$24,074 $37,002 $(7,406)
$(25,675)
======= ======= ================== =========== ===========
NoThe Company made no income tax payments which were madenot offset by
reimbursement for fiscal 2002, 2001 2000 and 1999.2000. Additionally a deferred tax
benefit of $267,000 and $7,004,000 has been allocated to stockholders' equity in
fiscal 2002 and 2001, respectively, for compensation expense for income tax
purposes in excess of amounts recognized for financial reporting purposes.
Income tax expense (benefit) differs from amounts computed by applying
the statutory federal rate as follows:
46
FISCAL YEAR ENDED JUNE 30,
--------------------------------------------------------------------------------------
2002 2001 2000
1999
-------- -------- ---------------------- ---------------- ----------------
Income tax computed at statutory rate..............rate.................. 35.0% (35.0)%35.0% (35.0)%
Amortization of goodwill disallowance..............disallowance.................. - 2.2 7.0
2.0
State taxes........................................taxes............................................ 2.8 1.4 -- ---
Change in valuation allowance and other............other................ (0.9) (1.4) 1.5
0.5
---- ----- ------------------- ---------------- ----------------
Change in valuation allowance and other................ 36.9% 37.2% (26.5)%
(32.5)%
==== ===== =================== ================ ================
Deferred tax assets (liabilities) are comprised of the following:
FISCAL YEAR ENDED JUNE 30,
----------------------------------------------------------
2002 2001
2000
---------- ------------------------ ---------------
(THOUSANDS)
Net operating loss and tax credit carry forwards....forwards........... $ 50,089 $ 69,376
$ 88,491
Property and equipment.............................. (182,442) (175,511)equipment..................................... (191,834) (183,068)
Self insurance reserves.............................reserves.................................... 6,254 405 1,616
Allowance for bad debts.............................debts.................................... 1,477 1,542
1,129
Acquisition expenses, expensed for tax.............. (626) (626)
Other...............................................Other...................................................... (2,456) 148
862
--------- ----------------------- ---------------
Net deferred tax liability..........................liability................................. (136,470) (111,597) (84,039)
Valuation allowance of deferred tax assets..........assets................. (13,520) (15,803)
(15,668)
--------- ----------------------- ---------------
Net deferred tax liability, net of valuation allowance.........................................allowance..... $(149,990) $(127,400)
$ (99,707)
========= ======================= ===============
49
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
11. INCOME TAXES (CONTINUED)
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, 2001,2002, the Company will have
available approximately $185,474,305$193,021,646 of net operating loss carryforwards (which
will continue to expire in fiscal 2002)2003). Approximately $53,570,522$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.
12.10. LEASING ARRANGEMENTS
The Company leases certain property and equipment under non-cancelable
operating leases that generally expire at various dates through fiscal 2006.2007. The
term of the operating leases generally run from 24 to 60 months with varying
payment dates throughout each month.
As of June 30, 2001,2002, the future minimum lease payments under
non-cancelable operating leases are as follows (in thousands):
47
LEASE
FISCAL YEAR ENDING JUNE 30, PAYMENTS
--------------------------- --------
2002........................................................2003.............................................. $ 4,689
2003........................................................ 4,587
2004........................................................ 4,493
2005........................................................ 4,426
2006........................................................ 2,626
-------
$20,821
=======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, $6,460,000 and
$7,313,000$6,460,000 for the fiscal years ended June 30, 2002, 2001 and 2000,
and 1999,
respectively.
13.11. 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 2000 and 19992000 were approximately
$2,123,000, $1,857,000 and $77,000, and $908,000, respectively.
50
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
14.12. TRANSACTIONS WITH RELATED PARTIES
In connection withEffective as of July 1, 2001, the negotiation of the terms of a five-yearCompany entered into an amended
and restated employment agreement with Mr. 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 as an inducementin 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 to enter into
such employment agreement, the Company entered into a separate agreement with
Mr. John, dated asand was comprised of August 2, 1999, which as amended through June 30, 2001,
provides that $6.5two components: (i) approximately $7.5 million in
loans previously madeprincipal 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 together withwill earn the accrued interest payable thereon, will be forgiven, ratably
during the ten yearincentive retention payment over a ten-year period
commencing onbeginning July 1, 2001, and endingwith one-tenth of the total bonus being earned on
June 30 2010. The agreement provides that the foregoing forgiveness of indebtedness is
predicated and conditioned uponeach year, beginning on June 30, 2002. For fiscal 2002, Mr. John
remaining employed byearned approximately $1.3 million of the retention incentive payment. If Mr.
John voluntarily terminates his employment with the Company during such period. In addition, in the event thator if Mr. John is
terminated by the Company for Cause (as defined in the agreement)Employment Agreement), or in the event that
Mr. John voluntarily terminates hiswill 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 agreement further
provides that the entire remaining principal balance of these loans, together
with accrued interest payable thereon, will become immediately due and payableCompany
other than for Cause, (ii) by Mr. John. However,John for Good Reason (as defined in the
event that Mr. John's employment is terminated for
"Good Reason"Employment Agreement), or(iii) as a result of Mr. John's death or "Disability"Disability
(as defined in the Employment Agreement), or (iv) as a result of a "ChangeChange in
Control" (all asControl (as defined in that agreement)the Employment Agreement), the agreement stipulates thatremaining unearned
balance of the remaining principal balance outstanding on the
loans, together with accrued interest thereonretention incentive payment will be forgiven.
In connection withtreated as earned as of
the negotiationdate of an employment agreement with Thomas K.
Grundman, the Company's Executive Vice President, Chief Financial Officer and
Chief Accounting Officer, the Company made a $240,000 short-term loan and a
$150,000 relocation loan to assist Mr. Grundman's relocation to the Company's
executive offices. Interest on these loans accrues at a rate of 6.125% per
annum. The short-term loan has been repaid. The relocation loan together with
accrued interest will be forgiven in three installments of $50,000 each on
July 1, 2000, 2001 and 2002; provided, however, that if Mr. Grundman's
employment is terminated during such period in a way that (i) triggers severance
obligations, all amounts owed shall be immediately forgiven or (ii) does not
trigger severance obligations, all amounts owed shall be immediately due and
payable.
15.event.
48
13. BUSINESS SEGMENT INFORMATION
The Company's reportable business segments are well servicing and
contract drilling. Oil and natural gas production operations previously wereare presented
separately as a reportable business segment and are now included in
"corporate/other."
WELL SERVICING: the Company's operations provide well servicing
(ongoing maintenance of existing oil and natural gas wells), workover (major
repairs or modifications necessary to optimize the level of production from
existing oil and natural gas wells) and production services (fluid hauling and
fluid storage tank rental).
CONTRACT DRILLING: the Company provides contract drilling services for
major and independent oil companies onshore the continental United States,
Argentina and Ontario, Canada.
The Company's management evaluates the performance of its operating
segments based on net income and operating profits (revenues less direct
operating expenses). Corporate expenses include general corporate expenses
associated with managing all reportable operating segments. Corporate 51
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
15. BUSINESS SEGMENT INFORMATION (CONTINUED)
assets
consist principally of cash and cash equivalents, deferred debt financing costs
and deferred income tax assets.
49
WELL CONTRACT CORPORATE
SERVICING DRILLING /OTHER/ 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.................................revenues ................................... $758,273 $107,639 $ 7,350 $ 873,262$873,262
Operating profit................................... 265,165profit ..................................... 257,949 30,273 2,886 298,324291,108
Depreciation, depletion and amortization...........amortization ............. 63,578 7,947 3,622 75,147
Interest expense...................................expense ..................................... 1,831 --- 54,729 56,560
Net income (loss) before extraordinary gain (loss)*............................................ . 109,159 9,466 (56,344) 62,281
Identifiable assets................................assets .................................. 664,611 95,473 278,325 1,038,409
Capital expenditures (excluding acquisitions)...... 50,799 ........ 51,064 15,884 15,437 82,12015,802 82,750
TWELVE MONTHS ENDED JUNE 30, 2000
Operating revenues.................................revenues ................................... $559,492 $ 68,428 $ 9,812$9,812 $ 637,732
Operating profit................................... 159,552profit ..................................... 150,769 10,129 5,665 175,346166,563
Depreciation, depletion and amortization...........amortization ............. 62,680 6,105 2,187 70,972
Interest expense...................................expense ..................................... 2,300 --- 69,630 71,930
Net income (loss) before extraordinary gain (loss)
*..................................................* .. 48,062 (1,664) (56,968)(66,968) (20,570)
Identifiable assets................................assets .................................. 635,304 89,574 322,754 1,047,632
Capital expenditures (excluding acquisitions)...... 30,098 ........ 26,464 8,282 3,422 41,802
TWELVE MONTHS ENDED JUNE 30, 1999
Operating revenues................................. $433,657 $ 50,613 $ 7,547 $ 491,817
Operating profit................................... 108,692 7,057 4,640 120,389
Depreciation, depletion and amortization........... 52,638 6,586 2,850 62,074
Interest expense................................... 1,659 18 65,724 67,401
Net income (loss) before extraordinary gain
(loss)*............................................ 15,447 (4,093) (64,612) (53,258)
Identifiable assets................................ 651,781 81,074 209,860 942,715
Capital expenditures (excluding acquisitions)...... 26,776 1,063 3,468 31,30738,173
------------------------
* --- 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. 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. Operating revenues and operating
profit for the Company's foreign operations, which includes Argentina and
Canada, were $26.9 million and $5.4 million, respectively, for the year ended
June 30, 1999.2002.
The Company had $84.1$27.9 million and $66.9$84.1 million of identifiable assets
as of June 30, 20012002 and 2000,2001, respectively, related to its foreign operations.
5250
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
16.14. SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
YEAR ENDED JUNE 30,
------------------------------2002 2001 2000
1999
-------- -------- --------
(IN THOUSANDS)---- ---- ----
(THOUSANDS)
Fair value of common stock issued in purchase transactions................................................transactions .......... $25,067 $8,120 $ -- $ --
Fair value of common stock issued to lender in lieu of
fees........................................................ -- -- 1$-
Fair value of common stock issued upon conversion of long-term debt..............................................debt . - 957 3,606
--
Capital lease obligations...................................obligations ........................................... 10,047 9,595 10,758 17,120
17.15. UNAUDITED SUPPLEMENTARY INFORMATION--QUARTERLYINFORMATION - QUARTERLY RESULTS OF OPERATIONS
Summarized quarterly financial data for fiscal 2001, 20002002, and 19992001 are as
follows:
51
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(IN THOUSANDS,--------- --------- --------- ---------
(THOUSANDS, EXCEPT PER SHARE AMOUNTS)
FISCAL 2002
Revenues ........................................... $ 249,237 $ 213,337 $ 170,241 $ 169,749
Income from operations ............................. 46,138 28,271 1,408 (10,560)
Net income (loss) before extraordinary gain (loss) . 28,996 17,368 635 (5,816)
Extraordinary gain (loss), net of tax .............. 180 2,091 (5,261) (47)
--------- --------- --------- ---------
Net income (loss) .................................. $ 29,176 $ 19,459 $ (4,626) $ (5,863)
========= ========= ========= =========
Earnings (loss) per share:
Basic - before extraordinary gain (loss) ......... $ 0.29 $ 0.17 $ 0.01 $ (0.05)
Extraordinary gain (loss), net of tax ............ - 0.02 (0.05) -
--------- --------- --------- ---------
Basic - after extraordinary gain (loss) .......... $ 0.29 $ 0.19 $ (0.04) $ (0.05)
========= ========= ========= =========
Diluted - before extraordinary gain (loss) ....... $ 0.28 $ 0.17 $ 0.01 $ (0.05)
Extraordinary gain (loss), net of tax ............ - 0.02 (0.05) -
--------- --------- --------- ---------
Diluted - after extraordinary gain (loss) ........ $ 0.28 $ 0.19 $ (0.04) $ (0.05)
========= ========= ========= =========
Weighted average shares outstanding:
Basic ............................................ 101,727 103,115 108,551 109,776
Diluted .......................................... 103,829 104,811 110,059 109,776
FISCAL 2001
Revenues............................................ $191,679 $203,911 $227,370 $250,302Revenues ........................................... $ 191,679 $ 203,911 $ 227,370 $ 250,302
Income (loss) from operations.......................operations ............................. 12,229 18,063 27,912 41,079
Net income (loss) before extraordinary gain (loss).............................................. ........ 7,510 11,094 17,587 26,090
Extraordinary gain (loss), net of tax...............tax .............. 1,197 68 (167) (669)
-------- -------- -------- ----------------- --------- --------- ---------
Net income (loss)............................................................................ $ 8,707 $ 11,162 $ 17,420 $ 25,421
======== ======== ======== ================= ========= ========= =========
Earnings (loss) per share:
Basic--beforeBasic - before extraordinary gain (loss)........... ......... $ 0.08 $ 0.11 $ 0.18 $ 0.26
Extraordinary gain (loss), net of tax.............tax ............ 0.01 -- --- - (0.01)
-------- -------- -------- --------
Basic--after--------- --------- --------- ---------
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),........................ 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
2000
Revenues............................................ $149,892 $159,389 $158,551 $169,900
Income (loss) from operations....................... (13,191) (7,953) (5,730) (1,102)
Net income (loss)========= ========= ========= =========
Diluted - before extraordinary gain (loss).............................................. (9,451) (5,693) (4,150) (1,276) ....... $ 0.08 $ 0.11 $ 0.17 $ 0.25
Extraordinary gain (loss), net of tax............... -- -- -- 1,611
Net income (loss)................................... (9,451) (5,693) (4,150) 335
-------- -------- -------- --------
53
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
17. UNAUDITED SUPPLEMENTARY INFORMATION--QUARTERLY RESULTS OF OPERATIONS
(CONTINUED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Earnings (loss) per share:
Basic--beforetax ............ 0.01 - - (0.01)
--------- --------- --------- ---------
Diluted - after extraordinary gain (loss)........... (0.11) (0.07) (0.05) (0.01)
Extraordinary gain (loss), net of tax............. -- -- -- 0.02
-------- -------- -------- --------
Basic--after extraordinary gain (loss)............ (0.11) (0.07) (0.05 0.01
======== ======== ======== ========
Diluted--before extraordinary gain (loss)......... (0.11) (0.07) (0.05) (0.01)
Extraordinary gain (loss), net of tax............. -- -- -- 0.02
-------- -------- -------- --------
Diluted--after extraordinary gain (loss).......... (0.11) (0.07) (0.05 0.01
======== ======== ======== ======== ........ $ 0.09 $ 0.11 $ 0.17 $ 0.24
========= ========= ========= =========
Weighted average shares outstanding:
Basic............................................. 82,738 82,738 84,633 85,567
Diluted........................................... 82,738 82,738 84,633 85,567Basic ............................................ 96,880 97,534 98,211 100,179
Diluted .......................................... 100,472 100,534 103,524 104,401
18.16. 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.
19.52
17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The Company's senior notes are guaranteed by all of the Company's
operating subsidiaries (except for theits 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
tranfertransfer 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.
54
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
CONDENSED CONSOLIDATING BALANCE SHEETS
JUNE 30, 2001
-------------------------------------------------------------------
NON-2002
------------------------------------------------------------------------
PARENT GUARANTOR GUARANTORNON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDARIESSUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------------ ------------ ----------------------- ------------ ------------
(IN THOUSANDS)
Assets:
Current assets.....................assets $ 10,68064,814 $ 165,653 $29,817117,140 $ --10,119 $ 206,150- $ 192,073
Net property and equipment......... 21,418 717,989 54,309 -- 793,716equipment 43,003 748,158 17,739 - 808,900
Goodwill, net......................net 3,374 184,379 2,122 -- 189,875197,144 551 - 201,069
Deferred costs, net................ 17,624 -- -- -- 17,624net 12,580 - - - 12,580
Intercompany receivables........... 664,592 -- -- (664,592) --receivables 537,416 - - (537,416) -
Other assets....................... 15,303 5,616 -- -- 20,919
--------assets 21,593 6,780 - - 28,373
---------- ------- ------------------- ---------- ---------- ----------
Total assets......................... $732,991 1,073,637 $86,248 $(664,592) $1,228,284
========assets $ 682,780 $1,069,222 $ 28,409 $ (537,416) $1,242,995
========== ======= =================== ========== ========== ==========
Liabilities and equity:
Current liabilities................liabilities $ 35,67148,388 $ 64,679 $15,20345,427 $ --2,813 $ 115,553- $ 96,628
Long-term debt..................... 470,668 15,331 (38) -- 485,961debt 420,717 - - - 420,717
Capital lease obligations 1,457 13,762 - - 15,219
Intercompany paybles............... -- 608,764 55,828 (664,592) --payables - 516,761 20,655 (537,416) -
Deferred tax liability............. 127,400 -- -- -- 127,400liability 149,990 - - - 149,990
Other long-term liabilities........ 8,240 14,252 -- -- 22,492liabilities 13,474 10,101 - - 23,575
Stockholders' equity............... 91,012 370,611 15,255 -- 476,878
--------equity 48,754 483,171 4,941 - 536,866
---------- ------- ------------------- ---------- ---------- ----------
Total liabilities and stockholders' equity............................. $732,991 $1,073,637 $86,248 $(664,592) $1,228,284
========equity $ 682,780 $1,069,222 $ 28,409 $ (537,416) $1,242,995
========== ======= =================== ========== ========== ==========
53
JUNE 30, 2000
-------------------------------------------------------------------
NON-2001
-----------------------------------------------------------------------------------------
PARENT GUARANTOR GUARANTORNON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDARIESSUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------------- ------------ ----------------------- ------------ ------------
(IN THOUSANDS)
Assets:
Current assets..................... $120,216assets $ 115,178 $18,19510,680 $ --165,653 $ 253,58929,817 $ - $ 206,150
Net property and equipment......... 7,308 704,531 48,722 -- 760,561equipment 21,418 717,989 54,309 - 793,716
Goodwill, net...................... 3,606 192,641 2,386 -- 198,633net 3,374 184,379 2,122 - 189,875
Deferred costs, net................ 18,855 -- -- -- 18,855net 17,624 - - - 17,624
Intercompany receivables........... 788,166 -- -- (788,166) --receivables 664,592 - - (664,592) -
Other assets....................... 9,062 5,565 -- -- 14,627
-------- ---------- -------assets 15,303 5,616 - - 20,919
----------- ----------- ----------- --------- ---------------------
Total assets......................... $947,213 $1,017,915 $69,303 $(788,166) $1,246,265
======== ========== =======assets $ 732,991 $ 1,073,637 $ 86,248 $(664,592) $ 1,228,284
=========== =========== =========== ========= =====================
Liabilities and equity:
Current liabilities................liabilities $ 33,63735,671 $ 47,736 $11,47564,679 $ --15,203 $ 92,848- $ 115,553
Long-term debt..................... 637,438 14,486 21 -- 651,945debt 470,578 - - - 470,578
Capital lease obligations 90 15,331 (38) 15,383
Intercompany paybles............... -- 740,268 47,898 (788,166) --payables - 608,764 55,828 (664,592) -
Deferred tax liability............. 99,707 -- -- -- 99,707liability 127,400 - - - 127,400
Other long-term liabilities........ 1,751 17,127 -- -- 18,8788,240 14,252 - - 22,492
liabilities
Stockholders' equity............... 174,680 198,298 9,909 -- 382,887
-------- ---------- -------equity 91,012 370,611 15,255 - 476,878
----------- ----------- ----------- --------- ---------------------
Total liabilities and
stockholders' equity............................. $947,213 $1,017,915 $69,303 $(788,166) $1,246,265
======== ========== =======equity $ 732,991 $ 1,073,637 $ 86,248 $(664,592) $ 1,228,284
=========== =========== =========== ========= =====================
55
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
YEAR ENDED JUNE 30, 2001
-------------------------------------------------------------------
NON-2002
----------------------------------------------------------------------------------------
PARENT GUARANTOR GUARANTORNON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDARIESSUBSIDIARIES ELIMINATIONS CONSOLIDATED
------------------- ------------ ----------------------- ------------ ------------
(IN THOUSANDS)
Revenues.............................Revenues $ 2,018 $816,724 $54,5201,247 $ -- $873,262768,106 $ 33,211 $ - $ 802,564
Costs and expenses:.................. -
Direct expenses.................... -- 533,807 41,131 -- 574,938expenses - 527,977 26,796 - 554,773
Depreciation, depletion and
amortization expense............. 1,353 69,714 4,080 -- 75,147expense 1,830 73,252 3,183 - 78,265
General and administrative expense.......................... 18,991 43,644 3,436 -- 66,071
Interest........................... 54,464 1,275 821 -- 56,560
Other.............................. 318 943 2 -- 1,263
-------- -------- ------- ------- --------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............. 75,126 649,383 49,470 -- 773,979
-------- -------- ------- ------- --------expenses 66,428 636,567 34,312 - 737,307
--------- --------- --------- --------- ---------
Income (loss) before income taxes.... (73,108) 167,341 5,050 -- 99,283taxes (65,181) 131,539 (1,101) - 65,257
Income tax (expense) benefit......... 27,247 (62,367) (1,882) -- (37,002)
-------- -------- ------- ------- --------benefit 24,045 (48,525) 406 - (24,074)
--------- --------- --------- --------- ---------
Net income (loss) before
extraordinary items................ (45,861) 104,974 3,168 -- 62,281items (41,136) 83,014 (695) - 41,183
Extraordinary items, net of tax...... 429 -- -- -- 429
-------- -------- ------- ------- --------tax (3,037) - - - (3,037)
--------- --------- --------- --------- ---------
Net income (loss).................... $(45,432) $104,974 $ 3,168(44,173) $ --83,014 $ 62,710
======== ======== ======= ======= ========(695) $ - $ 38,146
========= ========= ========= ========= =========
54
YEAR ENDED JUNE 30, 2000
-------------------------------------------------------------------
NON-2001
---------------------------------------------------------------------------
PARENT GUARANTOR GUARANTORNON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDARIESSUBSIDIARIES ELIMINATIONS CONSOLIDATED
----------------- ------------ ----------------------- ------------ ------------
(IN THOUSANDS)
Revenues..............................Revenues $ 790 $599,225 $37,7172,018 $ -- $637,732816,724 $ 54,520 $ - $ 873,262
Costs and expenses:
Direct expenses..................... -- 431,997 30,389 -- 462,386expenses - 540,987 41,167 - 582,154
Depreciation, depletion and
amortization expense.............. 1,162 66,453 3,357 -- 70,972expense 1,353 69,714 4,080 - 75,147
General and administrative expense........................... 11,101 44,473 3,198 -- 58,772
Interest............................ 69,802 1,527 601 -- 71,930
Other............................... -- 1,648 -- -- 1,648
-------- -------- ------- ------- --------19,158 37,558 3,402 - 60,118
expense
Interest 54,464 1,275 821 - 56,560
Other - - - - -
--------- --------- --------- ---------- ---------
Total costs and expenses.............. 82,065 546,098 37,545 -- 665,708
-------- -------- ------- ------- --------expenses 74,975 649,534 49,470 - 773,979
--------- --------- --------- ---------- ---------
Income (loss) before income taxes..... (81,275) 53,127 172 -- (27,976)taxes (72,957) 167,190 5,050 - 99,283
Income tax (expense) benefit.......... 21,516 (14,064) (46) -- 7,406
-------- -------- ------- ------- --------benefit 27,190 (62,310) (1,882) - (37,002)
--------- --------- --------- ---------- ---------
Net income (loss) before extraordinary items............................... (59,759) 39,063 126 -- (20,570)items (45,767) 104,880 3,168 - 62,281
Extraordinary items, net of tax....... 1,611 -- -- -- 1,611
-------- -------- ------- ------- --------tax 429 - - - 429
--------- --------- --------- ---------- ---------
Net income (loss)..................... $(58,148) $ 39,063(45,338) $ 126104,880 $ -- $(18,959)
======== ======== ======= ======= ========3,168 $ - $ 62,710
========= ========= ========= ========== =========
56
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
YEAR ENDED JUNE 30, 1999
-------------------------------------------------------------------
NON-2000
----------------------------------------------------------------------------
PARENT GUARANTOR GUARANTORNON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDARIESSUBSIDIARIES ELIMINATIONS CONSOLIDATED
----------------- ------------ ----------------------- ------------ ------------
(IN THOUSANDS)
Revenues..............................Revenues $ 1,086 $463,813 $26,918790 $ -- $491,817599,225 $ 37,717 $ - $ 637,732
Costs and expenses:
Direct expenses..................... -- 349,936 21,492 -- 371,428expenses - 440,741 30,428 - 471,169
Depreciation, depletion and
amortization expense.............. 428 58,403 3,243 -- 62,074expense 1,162 66,453 3,357 - 70,972
General and administrative expense........................... 14,962 34,490 3,656 -- 53,108
Interest............................ 65,724 1,559 118 -- 67,401
Other............................... 10,811 5,928 -- -- 16,739
-------- -------- ------- ------- --------expense 10,774 37,704 3,159 - 51,637
Interest 69,802 1,527 601 - 71,930
Other - - - - -
--------- --------- --------- ---------- ---------
Total costs and expenses.............. 91,925 450,316 28,509 -- 570,750
-------- -------- ------- ------- --------expenses 81,738 546,425 37,545 - 665,708
--------- --------- --------- ---------- ---------
Income (loss) before income taxes..... (90,839) 13,497 (1,591) -- (78,933)taxes (80,948) 52,800 172 - (27,976)
Income tax (expense) benefit.......... 29,547 (4,390) 518 -- 25,675
-------- -------- ------- ------- --------benefit 21,429 (13,977) (46) - 7,406
--------- --------- --------- ---------- ---------
Net income (loss) before extraordinary items............................... (61,292) 9,107 (1,073) -- $(53,258)items (59,519) 38,823 126 - (20,570)
Extraordinary items, net of tax....... -- -- -- -- --
-------- -------- ------- ------- --------tax 1,611 - - - 1,611
--------- --------- --------- ---------- ---------
Net income (loss)..................... $(61,292) $ 9,107 $(1,073)(57,908) $ -- $(53,258)
======== ======== ======= ======= ========38,823 $ 126 $ - $ (18,959)
========= ========= ========= ========== =========
55
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FISCAL YEAR ENDED JUNE 30, 2001
--------------------------------------------------------------------
NON-2002
--------------------------------------------------------------------------
PARENT GUARANTOR GUARANTORNON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDARIESSUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ----------------------- ------------ ------------
(IN THOUSANDS)
Net cash provided by (used in) operating activities...............activities $ 68,56795,948 $ 64,40878,577 $ 9,7424,191 $ --- $ 142,717178,716
Net cash provided by (used in) investing activities............... (19,459) (56,711) (7,180) -- (83,350)activities (37,188) (67,092) (4,469) - (108,749)
Net cash provided by (used in) financing activities............... (158,627) (8,456) (59) -- (167,142)activities (7,665) (9,637) (13) - (17,315)
Effect of exchange rate changes on cash - - (603) - (603)
--------- -------- ------- ---------------- --------- --------- ---------
Net increase (decrease) in cash...... (109,519) (759) 2,503 -- (107,775)cash 51,095 1,848 (894) - 52,049
Cash and cash equivalents at beginning of period................ 111,166 (1,246) (47) -- 109,873period 1,647 (2,005) 2,456 - 2,098
--------- -------- ------- ---------------- --------- --------- ---------
Cash and cash equivalents at end of period.............................period $ 1,64752,742 $ (2,005)(157) $ 2,4561,562 $ --- $ 2,09854,147
========= ======== ======= ================ ========= ========= =========
57
KEY ENERGY SERVICES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
JUNE 30, 2001, 2000 AND 1999
FISCAL YEAR ENDED JUNE 30, 2000
-------------------------------------------------------------------
NON-2001
--------------------------------------------------------------------------
PARENT GUARANTOR GUARANTORNON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDARIESSUBSIDIARIES ELIMINATIONS CONSOLIDATED
----------------- ------------ ----------------------- ------------ ------------
(IN THOUSANDS)
Net cash provided by (used in) operating activities...............activities $ 18,96268,932 $ 10,43464,673 $ 5,4649,742 $ --- $ 34,860143,347
Net cash provided by (used in) investing activities............... (4,468) (26,671) (6,627) -- (37,766)activities (19,824) (56,976) (7,180) - (83,980)
Net cash provided by (used in) financing activities............... 80,070 9,287 (56) -- 89,301
-------- -------- ------- ------- --------activities (158,627) (8,456) (59) - (167,142)
--------- --------- --------- --------- ---------
Net increase (decrease) in cash...... 94,564 (6,950) (1,219) -- 86,395cash (109,519) (759) 2,503 - (107,775)
Cash and cash equivalents at beginning of period................ 16,602 5,704 1,172 -- 23,478
-------- -------- ------- ------- --------period 111,166 (1,246) (47) - 109,873
--------- --------- --------- --------- ---------
Cash and cash equivalents at end of period............................. $111,166period $ (1,246)1,647 $ (47)(2,005) $ -- $109,873
======== ======== ======= ======= ========2,456 $ - $ 2,098
========= ========= ========= ========= =========
FISCAL YEAR ENDED JUNE 30, 1999
--------------------------------------------------------------------
NON-2000
--------------------------------------------------------------------------
PARENT GUARANTOR GUARANTORNON-GUARANTOR
COMPANY SUBSIDIARIES SUBSIDARIESSUBSIDIARIES ELIMINATIONS CONSOLIDATED
--------- ------------ ----------------------- ------------ ------------
(IN THOUSANDS)
Net cash provided by (used in) operating activities...............activities $ (49,167)18,962 $ 26,50810,434 $ 9,2325,464 $ --- $ (13,427)34,860
Net cash provided by (used in) investing activities............... (272,620) (13,986) (8,048) -- (294,654)activities (4,468) (26,671) (6,627) - (37,766)
Net cash provided by (used in) financing activities............... 313,526 (7,196) (36) -- 306,294activities 80,070 9,287 (56) - 89,301
--------- -------- ------- ---------------- --------- --------- ---------
Net increase (decrease) in cash...... (8,261) 5,326 1,148 -- (1,787)cash 94,564 (6,950) (1,219) - 86,395
Cash and cash equivalents at beginning of period................ 24,863 378 24 -- 25,265period 16,602 5,704 1,172 - 23,478
--------- -------- ------- ---------------- --------- --------- ---------
Cash and cash equivalents at end of period.............................period $ 16,602111,166 $ 5,704(1,246) $ 1,172(47) $ --- $ 23,478109,873
========= ======== ======= ================ ========= ========= =========
5818. ARGENTINA FOREIGN CURRENCY TRANSACTION LOSS
The local currency is the functional currency for the Company's
foreign operations in Argentina and Canada. The cumulative translation gains
and losses, resulting from translating each foreign subsidiary's financial
statements from the functional currency to U.S. dollars are included in other
comprehensive income and accumulated in stockholders' equity until a partial
or complete sale or liquidation of the Company's net investment in the
foreign entity.
Since 1991, the Argentine peso has been tied to the U.S. dollar at a
conversion ratio of 1:1. However, in December 2001, the Government of Argentina
announced an exchange holiday and, as a result, Argentine pesos could not be
56
exchanged into other currencies at December 31, 2001. On January 5 and 6, 2002,
the Argentine Congress and Senate gave the President of Argentina emergency
powers and the ability to suspend the law that created the fixed conversion
ratio of 1:1. The Government subsequently announced the creation of a dual
currency system in which certain qualifying transactions will be settled at an
expected fixed conversion ratio of 1.4:1 while all other transactions will be
settled using a free floating market conversion ratio. Under existing guidance,
dividends would not receive the fixed conversion ratio. On January 11, 2002, the
exchange holiday was lifted, making it possible again to buy and sell Argentine
pesos. Banks were legally allowed to exchange currencies, but transactions were
limited and generally took place at exchange houses. These transactions were
conducted primarily by individuals as opposed to commercial transactions, and
occurred at free conversion ratios ranging between 1.6:1 and 1.7:1.
Due to the events described above, which resulted in the temporary
lack of exchangeability of the two currencies at December 31, 2001, the
Company translated the assets and liabilities of its Argentine subsidiary at
December 31, 2001 using a conversion ratio of 1.6:1, which management
believes was indicative of the free floating conversion ratio when the
currency market re-opened on January 11, 2002. At June 30, 2002, the Company
used a conversion ratio of 3.9:1 to translate the assets and liabilities of
its Argentine subsidiary. As a result, a foreign currency translation loss of
approximately $48.3 million is included in other comprehensive income, a
component of stockholders' equity, at June 30, 2002. Since the 1:1 conversion
ratio was in existence prior to December 2001, income statement and cash
flows information for the six months ended December 31, 2001 has been
translated using the historical 1:1 conversion ratio. After December 31,
2001, revenues and expenses are translated using the average exchange rate
during the reporting period.
Additionally, the Argentine government has indicated that as part of
its monetary policy changes, it will re-denominate certain consumer loans from
U.S. dollar-denominated to Argentine peso- denominated. As a result, the Company
recorded a foreign currency transaction loss of $1.8 million in the three months
ended December 31, 2001 related to accounts receivable subject to certain U.S.
dollar-denominated contracts held by its Argentine subsidiary which are subject
to re-denomination. These receivables are subject to additional negotiation with
the Company's customers which may result in recovery of a portion of this loss.
In the six months ended June 30, 2002, the Company recovered approximately $0.4
million resulting in a net foreign currency transaction loss of approximately
$1.4 million for fiscal 2002.
19. SUBSEQUENT EVENTS-ACQUISITION OF Q SERVICES, INC. [UNAUDITED]
On July 19, 2002, the Company acquired Q Services, Inc. ("QSI")
pursuant to an Agreement and Plan of Merger dated May 13, 2002, as amended,
by and among the Company, Key Merger Sub, Inc. and QSI. As consideration for
the merger, the Company issued approximately 17.2 million shares of its
common stock to QSI shareholders and assumed approximately $74 million of
QSI's indebtedness, net of working capital. The aggregate value of the
purchase price was approximately $221 million. Prior to the acquisition, QSI
was a privately held corporation conducting field production, pressure
pumping and other service operations in Louisiana, New Mexico, Oklahoma,
Texas and the Gulf of Mexico.
20. SUBSEQUENT EVENTS-NEW SENIOR CREDIT FACILITY [UNAUDITED]
On July 15, 2002, the Company entered into a Third Amended and
Restated Credit Agreement (the "New Senior Credit Facility"). The New Senior
Credit Facility consists of a $150,000,000 revolving loan facility with a
$40,000,000 sublimit for letters of credit. The loans are secured by most of
the tangible and intangible assets of the Company. The revolving loan
commitment will terminate on July 15, 2005 and all revolving loans must be
paid on or before that date. The revolving loans bear interest based upon, at
the Company's option, the prime rate plus a variable margin of 0.00% to 0.75%
or a Eurodollar rate plus a variable margin of 1.25% to 2.75%.
The New Senior Credit Facility contains various financial covenants,
including: (i) a maximum consolidated senior leverage ratio of 2.75 to 1.00,
(ii) a minimum consolidated fixed coverage ratio of 1.50 to 1.00, and (iii) a
maximum consolidated total leverage ratio of 3.50 to 1.00. The Company is
also required to maintain a minimum net worth of $436,972,000 plus (i) 50% of
consolidated net income and (ii) 75% of the net cash proceeds from the sale
of equity.
The New Senior Credit Facility subjects the Company to other
restrictions, including restrictions upon the Company's ability to incur
additional debt, liens and guarantee obligations, to merge or consolidate
with other persons, to make acquisitions, to sell assets, to make dividends,
purchases of our stock or subordinated debt, or to make investments, loans
and advances or changes to debt instruments and organizational documents.
All obligations under the New Senior Credit Facility are guaranteed by most
of the Company's subsidiaries and are secured by most of the Company's
assets, including the Company's accounts receivable, inventory and most
equipment.
At September 30, 2002 as a result of retiring certain long-term debt
of QSI, there was approximately $62.0 million outstanding under the New
Senior Credit Facility revolver and $28.0 million in outstanding letters of
credit.
57
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, 20012002 and 2000,2001, 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, 2001.2002. In connection with our audits of the consolidated financial
statements, we also have audited the financial statement schedule listed in the
Index at Item 14.15. 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, 20012002 and 2000,2001, and the
results of their operations and their cash flows for each of the years in the
three-year period ended June 30, 2001,2002, 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 81 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
Midland,Dallas, Texas
August 16, 2001
592002
58
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
None.
PART III
ITEMS 10-13.
Pursuant to Instruction G(3) to Form 10-K, the information required in
Items 10-13 is incorporated by reference to the Company's definitive proxy
statement, which will be filed with the Commission pursuant to Regulation 14A
within 120 days of June 30, 2001.2002.
ITEM 14. DISCLOSURE CONTROLS AND PROCEDURES
(b) Changes in Internal Controls
There were no significant changes in the Company's internal
controls during fiscal 2002 nor did any other factors exist
that could significantly affect such controls through the date
of this report.
PART IV
ITEM 14.15. 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, 2001:2002:
Schedule II-Consolidated Valuation and Qualifying Accounts...................S-1Accounts...S-1
The supplemental schedules other than the one listed above are omitted
because of the absence of the conditions under which they are required or
because the required information is included in the Consolidated Financial
Statements or Notes thereto.
(3) Exhibits:
3.1 Amended and Restated Articles of Incorporation of the Company.
(Incorporated by reference to the Company's Registration Statement
on Form S-4, Registration No. 333-369).
3.2 Amended and Restated By-Laws of the Company. (Incorporated by
reference to the Company's Registration Statement on Form S-4
dated March 8, 1996, Registration No. 333-369).
3.3 Amendment to the Amended and Restated Articles of Incorporation of
the Company. (Incorporated by reference to Exhibit 3.1 of the
Company's Current Report on Form 8-K dated February 2, 1998, File
No. 1-8038).
59
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).
60
3.6 Unanimous Consent of the Board of Directors of the Company
dated January 11, 2000, limiting the designation of the
additional authorized shares to common stock (Incorporated
by reference to Exhibit 3.2 of the Company's Quarterly
Report on Form 10-Q for the quarter ended March 31, 2000,
File No. 1-8038).
4.1 7% Convertible Subordinated Debenture of the Company due
July 1, 2003. (Incorporated by reference to Exhibit 4.1 of
the Company's Annual Report on Form 10-K dated June 30,
1996,3.6 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 Indenture for the 7% Convertible Subordinated Debentures of
the Company due July 1, 2003. (Incorporated by reference to
Exhibit 4.2 of the Company's Annual Report on Form 10-K
dated June 30, 1996, File No. 1-8038).
4.3 First Supplemental Indenture dated as of November 20, 1996
by and between Key Energy Group, Inc. and American Stock
Transfer & Trust Company, as Trustee. (Incorporated by
reference to Exhibit 10(i) to the Company's Quarterly Report
on Form 10-Q dated December 31, 1996, File No. 1-8038).
4.4 Registration Rights Agreement among the Company, McMahan
Securities Co., L.P. and Rausher Pierce Refsnes, Inc., dated
as of July 3, 1996. (Incorporated by reference to Exhibit
4.3 of the Company's Annual Report on Form 10-K dated
June 30, 1996, File No. 1-8038).
4.5 Registration Rights Agreement dated as of March 2, 1996
among the Company and certain of its stockholders.
(Incorporated by reference to Exhibit 4.3 of the Company's
Registration Statement on Form S-4, Registration
No. 333-369).
4.6 Form of Common Stock Purchase Warrant to Purchase Key Common
Stock issued in connection with the WellTech Merger.
(Incorporated by reference to Exhibit 4.1 of the Company's
Registration Statement on Form S-4, Registration
No. 333-369).
4.7 Indenture dated as of September 25, 1997, among Key Energy
Group, Inc. and American Stock Transfer and Trust Company.
(Incorporated by reference to Exhibit 10(a) of the Company's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 1997, File No. 1-8038).
4.8 Registration Rights Agreement among Key Energy Group, Inc.,
Lehman Brothers Inc., and McMahan Securities Co. L.P. dated
as of September 25, 1997. (Incorporated by reference to
Exhibit 10(a) of the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1997, File
No. 1-8038).
4.9 Indenture dated February 20, 1997 between Dawson Production
Services, Inc. and U.S. Trust Company of Texas, N.A.
(Incorporated by reference to Exhibit 99.10 of the Company's
Current Report on Form 8-K dated September 28, 1998, File
No. 1-8038).
4.10 Supplemental Indenture dated September 21, 1998, among Key
Energy Group, Inc., its Subsidiaries and U.S. Trust Company
of Texas, N.A. (Incorporated by reference to Exhibit 99.11
of the Company's Current Report on Form 8-K dated September
28, 1998, File No. 1-8038).
4.11 Warrant Agreement dated as of January 22, 1999 between the Company
and The Bank of New York, a New York banking corporation as
warrant agent. (Incorporated by reference to Exhibit 99(b) of the
Company's Form 8-K filed on February 3, 1999, File No. 1-8038).
614.3 Indenture dated as of January 22, 1999 between the Company and The
Bank of New York as trustee. (Incorporated by reference to Exhibit
99(c) of the Company's Form 8-K filed on February 3, 1999, File
No. 1-8038).
4.4 Warrant Registration Rights Agreement dated January 22, 1999, by
and among the Company and Lehman Brothers Inc., Bear, Stearns &
Co. Inc., F.A.C./Equities, a division of First Albany Corporation,
60
4.12 Indenture dated as of January 22, 1999 between the Company
and The Bank of New York as trustee. (Incorporated by
reference to Exhibit 99(c) of the Company's Form 8-K filed
on February 3, 1999, File No. 1-8038).
4.13 Registration Rights Agreement dated January 22, 1999 by and
among the Registrant, certain of its subsidiaries, and
Lehman Brothers, Inc., Bear, Stearns & Co. Inc.,
F.A.C./Equities, a division of First Albany Corporation, and
Dain Rauscher Wessels, a division of Dain Rauscher
Incorporated. (Incorporated by reference to Exhibit 99(d) of
the Company's Form 8-K filed on February 3, 1999, File
No. 1-8038).
4.14 Warrant Registration Rights Agreement dated January 22,
1999, by and among the Company and Lehman Brothers Inc.,
Bear, Stearns & Co. Inc., F.A.C./ Equities, a division of
First Albany Corporation, and Dain Rauscher Wessels, a
division of Dain Rauscher Incorporated. (Incorporated by
reference to Exhibit 99(e) of the Company's Form 8-K filed
on February 3, 1999, File No. 1-8038).
4.15 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)
4.16 Registration Rights Agreement dated March 6, 2001 among the
Company, certain of its subsidiaries, Lehman Brothers, Inc.,
and Bear Stearns & Co., Inc. (Incorporated by reference to
Exhibit 99.2 of the Company's Current Report of Form 8-K
dated 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 Amended and Restated Senior Credit Facility among Key Energy
Group, Inc. and several other financial institutions dated
as of June 6, 1997 as amended and restated through November
6, 1997. (Incorporated by reference to Exhibit 10(s) of the
Company's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1997, File No. 1-8038).
10.3 First Amendment to the Amended and Restated Credit Agreement
dated as of June 6, 1997, as amended and restated through
November 6, 1997 dated December 3, 1997. (Incorporated by
reference to Exhibit 10(t) of the Company's Quarterly Report
on Form 10-Q for the quarter ended December 31, 1997, File
No. 1-8038).
10.4 Escrow Agreement among Key Energy Group, Inc., Lehman
Brothers Inc., Lehman Commercial Paper Inc. and The Bank of
New York, dated as of September 14, 1998 (Incorporated by
reference to Exhibit 99.6and 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).
62
10.5 $550,000,000 Second Amended and Restated Senior Credit
Facility, among Key Energy Group, Inc., PNC Bank, National
Association,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., PNC Capital Markets,
Inc. and the several lenders from time to time parties
thereto, dated as of June 6, 1998, as
amended and restated through September 14, 1998 (Incorporated by
reference to Exhibit 99.8 of the Company's Current Report on Form
8-K dated September 28, 1998, File No. 1-8038).
10.4 Intercreditor and Collateral Agency Agreement, dated as of
September 14, 1998. (Incorporated by reference to Exhibit 99.9 of
the Company's Current Report on Form 8-K dated September 28, 1998,
File No. 1-8038).
10.5 Consulting Agreement, dated as of October 7, 1998, by and among
Key Energy Group, Inc. and Michael E. Little. (Incorporated by
reference to Exhibit 10(a) of the Company's Quarterly Report on
Form 10-Q for the quarter ended December 31, 1998, File No.
1-8038).
10.6 Non-Compete Agreement, dated November 13, 1998, by and between Key
Energy Group, Inc. and James J. Byerlotzer. (Incorporated by
reference to Exhibit 10(c) of the Company's Quarterly Report on
Form 10-Q for the quarter ended December 31, 1998, File No.
1-8038).
10.7 Non-Compete Agreement, dated October 20, 1998, by and between Key
Energy Group, Inc. and Joseph B. Eustace. (Incorporated by
reference to Exhibit 10(e) of the Company's Quarterly Report on
Form 10-Q for the quarter ended December 31, 1998, File No.
1-8038).
10.8 Consulting Agreement, dated as of November 12, 1998, by and among
Key Energy Group, Inc. and C. Ron Laidley. (Incorporated by
reference to Exhibit 10(f) of the Company's Quarterly Report on
Form 10-Q for the quarter ended December 31, 1998, File No.
1-8038).
10.9 Key Energy Group, Inc. Performance Compensation Plan.
(Incorporated by reference to Exhibit 10(g) of 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).
10.6 Amended and Restated Master Guarantee and Collateral
Agreement made by Key Energy Group, Inc. and certain of its
subsidiaries in favor of Norwest Bank Texas, N.A., dated as
of June 6, 1998, as amended and restated through September
14, 1998 (Incorporated by reference to Exhibit 99.8 of the
Company's Current Report on Form 8-K dated September 28,
1998, File No. 1-8038).
10.7 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).
10.8 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).
10.9 Employment Agreement, dated November 13, 1998, by and
between Key Energy Group, Inc. and James J. Byerlotzer.
(Incorporated by reference to Exhibit 10(b) the Company's
Quarterly Report on Form 10-Q for the quarter ended December 31,
1998, File No. 1-8038).
10.10 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).
10.11 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).
10.12 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).
10.13 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).
10.14 First Amendment, dated as of December 3, 1997, to the Second
Amended and Restated Senior Credit
61
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).
6310.11 Second Amendment, dated as of December 29, 1998, to the Second
Amended and Restated Senior Credit Facility, dated as of June 6,
1997, as amended and restated through September 14, 1998, and as
amended by the First Amendment dated as of November 19, 1998.
(Incorporated by reference to Exhibit 10(i) of the Company's
Quarterly Report on Form 10-Q for the quarter ended December 31,
1998, File No. 1-8038).
10.12 Purchase Agreement dated January 19, 1999 by and among the
Registrant, certain of its subsidiaries, Lehman Brothers, Inc.,
Bear, Stearns & Co. Inc., First Albany Corporation, Dain Rauscher
Wessels, a division of Dain Rauscher Incorporated. (Incorporated
by reference to Exhibit 99(a) of the Company's Form 8-K filed on
February 3, 1999, File No. 1-8038).
10.13 Employment Agreement between the Company and Michael R. Furrow
dated as of January 4, 1999. (Incorporated by reference to Exhibit
10(g) of the Company's Quarterly Report on Form 10-Q for the
quarter ended December 31, 1998, File No. 1-8038).
10.14 Third Amendment, dated as of April 8, 1999, to the Second Amended
and Restated Senior Credit Facility, among the Company, the
several lenders from time to time parties thereto, PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent and PNC Capital Markets, Inc., as
Arranger. (Incorporated by reference to Exhibit 99.5 of the
Company's Current Report on Form 10-K dated April 8, 1999, File
No. 1-8038).
10.15 Fourth Amendment, dated as of April 15, 1999, to the Second
Amended and Restated Senior Credit Facility, among the Company,
the several lenders from time to time parties thereto, PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent and PNC Capital Markets, Inc., as
Arranger. (Incorporated by reference to Exhibit 99.6 of the
Company's Current Report on Form 10-K dated April 8, 1999, File
No. 1-8038).
10.16 Fifth Amendment, dated as of May 10, 1999, to the Second Amended
and Restated Senior Credit Facility, among the Company, the
several lenders from time to time parties thereto, PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent, and PNC Capital Markets, Inc., as
Arranger. (Incorporated by reference to Exhibit 10.91 of the
Company's Annual Report on Form 10-K dated June 30, 1999, File No.
1-8038).
62
10.15 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).
10.16 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).
10.17 Employment Agreement between the Company and William C.
McCurdy dated as of January 4, 1999. (Incorporated by
reference to Exhibit 10(f) of the Company's Quarterly Report
on Form 10-Q for the quarter ended December 31, 1998, File
No. 1-8038).
10.18 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).
10.19 Purchase Agreement, among the Company, Green-Cohn Group,
LLC, ZPG Securities L.L.C. and DFG Corporation, dated as of
April 15, 1999. (Incorporated by reference to Exhibit 99.2
of the Company's Current Report on Form 8-K dated April 8,
1999, File No. 1-8038).
10.20 Commitment Letter, between the Company and PNC Investment
Corp., dated April 15, 1999. (Incorporated by reference to
Exhibit 99.3 of the Company's Current Report on Form 8-K
dated April 8, 1999, File No. 1-8038).
10.21 Fee letter, between the Company and PNC Capital Markets,
Inc., dated April 15, 1999. (Incorporated by reference to
Exhibit 99.4 of the Company's Current Report on Form 8-K
dated April 8, 1999, File No. 1-8038).
10.22 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).
10.23 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).
10.24 Underwriting Agreement, dated May 4, 1999, among the
Company, and Friedman, Billings, Ramsey & Co., Inc., for
itself and as representative for the other underwriter named
in Schedule I thereto. (Incorporated by reference to Exhibit
1.1 of the Company's Current Report on Form 8-K dated May 4,
1999, File No. 1- 8038).
64
10.25 Letter Agreement, dated May 4, 1999, among the Company, PNC
Capital Markets, Inc. and PNC Investment Corp. (Incorporated
by reference to Exhibit 99.1 of the Company's Current Report
on Form 8-K dated May 4, 1999, File No 1-8038).
10.26 Fifth Amendment, dated as of May 10, 1999, to the Second
Amended and Restated Senior Credit Facility, among the
Company, the several lenders from time to time parties
thereto, PNC Bank, National Association, as Administrative
Agent, Norwest Bank Texas, N.A., as Collateral Agent, and
PNC Capital Markets, Inc., as Arranger. (Incorporated by
reference to Exhibit 10.91 of the Company's Annual Report on
Form 10-K dated June 30, 1999, File No. 1-8038).
10.27 Consulting Agreement between Key Energy Group, Inc. and The
Old Hill Company LLC dated as of December 2, 1998.
(Incorporated by reference to Exhibit 10.92 of the Company's
Annual Report on Form 10-K dated June 30, 1999, File
No. 1-8038).
10.28 Amended and Restated Employment Agreement dated July 1,
1999, between Francis D. John and Key Energy Services, Inc.
(Incorporated by reference to Exhibit 10.1 of the Company's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 1999, File No. 1-8038).
10.29 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).
10.30 Employment Agreement dated July 1, 1999, between Danny R.
Evatt and Key Energy Services, Inc.(Incorporated by
reference to Exhibit 10.3 of the Company's Quarterly Report
on Form 10-Q for the quarter ended September 30, 1999, File
No. 1-8038).
10.31 Employment Agreement dated July 1, 1999, between James J.
Byerlotzer and Key Energy Services, Inc. (Incorporated by
reference to Exhibit 10.4 of the Company's Quarterly Report
on Form 10-Q for the quarter ended September 30, 1999, File
No. 1-8038).
10.32 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).
10.33 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).
10.34 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).
10.35 Confidential Separation and Release Agreement dated as of
July 1, 1999, between Key Energy Services, Inc. and Stephen
E. McGregor (Incorporated by reference to Exhibit 10.8 of the Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1999, File No. 1-8038).
6510.18 Agreement dated as of August 2, 1999, between Francis D. John and
Key Energy Services, Inc. (Incorporated by reference to Exhibit
10.5 of the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999, File No. 1-8038).
10.19 Promissory Note dated August 3, 1999, made by Thomas K. Grundman
in favor of Key Energy Services, Inc. (Incorporated by reference
to Exhibit 10.6 of the Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999, File No. 1-8038).
10.20 Demand Note dated August 3, 1999, made by Thomas K. Grundman in
favor of Key Energy Services, Inc. (Incorporated by reference to
Exhibit 10.7 of the Quarterly Report on Form 10-Q for the quarter
ended September 30, 1999, File No. 1-8038).
10.21 Amendment No. 1 dated as of December 1, 1999, to Agreement dated
as of August 2, 1999, between Francis D. John and Key Energy
Services, Inc. (Incorporated by reference to Exhibit 10.1 of the
Company's Quarterly Report on Form 10-Q for the quarter ended
December 31, 1999, File No. 1-8038).
10.22 Sixth Amendment, dated as of July 14, 1999, to the Second Amended
and Restated Senior Credit Facility, among the Company, the
several lenders from time to time parties thereto, PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent, and PNC Capital Markets, Inc., as
Arranger (Incorporated by reference to Exhibit 10.1 of the
Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2000, File No. 1-8038).
10.23 Seventh Amendment, dated as of March 1, 2000, to the Second
Amended and Restated Senior Credit Facility, among the Company,
the several lenders from time to time parties thereto, PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent, and PNC Capital Markets, Inc., as
Arranger (Incorporated by reference to Exhibit 10.2 of the
Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2000, File No. 1-8038).
10.24 Production and Delivery Agreement dated March 31, 2000, among
Odessa Exploration Incorporated and Norwest Energy Capital, Inc.,
(Incorporated by reference to Exhibit 10.3 of the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31,
2000, File No. 1-8038).
10.25 Agreement dated March 31, 2000, among Odessa Exploration
Incorporated, Norwest Energy Capital, Inc. and the Company
(Incorporated by reference to Exhibit 10.4 of the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31,
2000, File No. 1-8038).
10.26 Underwriting Agreement dated June 27, 2000, among the Company and
Lehman Brothers Inc. for itself and as Representative of the
several underwriters named in Schedule I thereto (Incorporated by
reference to Exhibit 1.1 of the Company's Current Report on Form
8-K dated June 29, 2000, File No. 1-8038).
10.27 Amendment No. 2 dated as of June 16, 2000 to Agreement dated as of
August 2, 1999, as amended
63
10.36 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).
10.37 Amendment No. 1 dated as of November 24, 1999, to the
Confidential Separation and Release Agreement dated as of
July 1, 1999, between Key Energy Services, Inc. and Stephen
E. McGregor (Incorporated by reference to Exhibit 10.2 of
the Company's Quarterly Report on Form 10-Q for the quarter
ended December 31, 1999, File No. 1-8038).
10.38 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).
10.39 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).
10.40 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).
10.41 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).
10.42 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).
10.43 Membership Interest Exchange Agreement dated April 5, 2000
by and between Tetra Services, Inc. and Brooks Well
Servicing, Inc. (Incorporated by reference to Exhibit 10.82
of the Company's Annual Report on Form 10-K dated June 30,
2000, File No. 1-8038).
10.44 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).
10.45between 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).
66
10.46 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).
10.47 Purchase Agreement dated March 1, 2001 among the Company,
certain of its subsidiaries, Lehman Brothers, Inc., and Bear
Stearns & Co., Inc. (Incorporated by reference to Exhibit
1.1 of the Company's Form 8-K filed on March 20, 2001, File
No. 1-8038)
10.48 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)
10.49*10.29 Letter Agreement Amendment dated July 1, 2000 to the Demand Note
dated August 3, 1999 made by Thomas K. Grundman in favor of Key
Energy Services, Inc. (Incorporated by reference to Exhibit 10.2of
the Company's Quarterly Report of Form 10-Q for the quarter ended
September 30, 2000, File No. 1-8038).
10.30 Purchase Agreement dated March 1, 2001 among the Company, certain
of its subsidiaries, Lehman Brothers, Inc., and Bear Stearns &
Co., Inc. (Incorporated by reference to Exhibit 1.1 of the
Company's Form 8-K filed on March 20, 2001, File No. 1-8038).
10.31 Eighth Amendment to the Second Amended and Restated Senior Credit
Facility, dated as of June 6, 1997, as amended and restated
through September 14, 1998 and as further amended, among Key
Energy Group, Inc. (now known as Key Energy Services, Inc.), the
several Lenders from time to time parties thereto, PNC Bank,
National association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent and PNC Capital markets, Inc., as
Arranger. (Incorporated by reference to Exhibit 99.3 of the
Company's Form 8-K filed on March 20, 2001, File No. 1-8038).
10.32 Amendment No. 3 dated as of May 14, 2001 to Agreement dated as of
August 2, 1999, as amended, between Francis D. John and Key Energy
Services, Inc. (Incorporated by reference to Exhibit 10.49 of the
Company's Annual Report on Form 10-K dated June 30, 2001, File No.
1-8038).
10.33 Second Amended and Restated Employment Agreement dated October 16,
2001 between Francis D. John and Key Energy Services, Inc.
(Incorporated by reference to Exhibit 10.50 of the Company's
Annual Report on Form 10-K/A dated June 30, 2001, File No.
1-8038).
10.34 Ninth Amendment to the Second Amended and Restated Credit
Agreement, dated as of June 6, 1997, as amended and restated
through September 14, 1998 and as further amended, among Key
Energy Group, Inc. (now known as Key Energy Services, Inc.), the
several Lenders from time to time parties thereto, PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent and PNC Capital Markets, Inc., as
Arranger. (Incorporated by reference to Exhibit 10.1 of the
Company's Quarterly Report on Form 10-Q dated September 30, 2001,
File 1-8038).
10.35 Underwriting Agreement, dated December 13, 2001, between
Registrant and Lehman Brothers Inc. (Incorporated by reference to
Exhibit 1.1 of the Company's Current Report on Form 8-K dated
December 19, 2001, File No. 1-8038).
10.36 Tenth Amendment to the Second Amended and Restated Credit
Agreement, dated as of June 6, 1997, as amended and restated
through September 14, 1998 and as further amended, among Key
Energy Group, Inc. (now known as Key Energy Services, Inc.), the
several Lenders from time to time parties thereto, PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent and PNC Capital Markets, Inc., as
Arranger. (Incorporated by reference to Exhibit 10.1 of the
Company's Form 8-K filed on December 19, 2001, File 1-8038).
10.37 Employment Agreement between Key Energy Services, Inc. and Royce
W. Mitchell dated December 31, 2001. (Incorporated by reference to
Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q dated
December 31, 2001, File 1-8038).
10.38 Employment Agreement between Key Energy Services, Inc. and James
Byerlotzer dated December 31, 2001. (Incorporated by reference to
Exhibit 10.4 of the Company's Quarterly Report on Form 10-Q dated
December 31, 2001, File 1-8038).
10.39 First Amendment to Second Amended and Restated Employment
Agreement between Francis D. John and Key Energy Services, Inc.
dated December 31, 2001. (Incorporated by reference to Exhibit
10.5 of the Company's Quarterly Report on Form 10-Q dated
December 31, 2001, File 1-8038).
10.40 Underwriting Agreement, dated February 22, 2002, among the
Registrant and Lehman Brothers Inc., Bear Stearns & Co. Inc. and
First Albany Corporation. (Incorporated by reference to Exhibit
1.1 of the Company's Current Report on Form 8-K dated February
27, 2002, File No. 1-8038).
10.41 Eleventh Amendment to the Second Amended and Restated Credit
Agreement, dated as of June 6, 1997, as amended and restated
through September 14, 1998 and as further amended, among Key
Energy Group, Inc. (now known as Key Energy Services, Inc.), the
several Lenders from time to time parties thereto, PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent and PNC Capital Markets, Inc., as
Arranger. (Incorporated by reference to Exhibit 10.1 of the
Company's Current Report on Form 8-K dated February 27, 2002, File
1-8038).
64
10.42 Twelfth Amendment to the Second Amended and Restated Credit
Agreement, dated as of June 6, 1997, as amended and restated
through September 14, 1998 and as further amended, among Key
Energy Group, Inc. (now known as Key Energy Services, Inc.), the
several Lenders from time to time parties thereto, PNC Bank,
National Association, as Administrative Agent, Norwest Bank Texas,
N.A., as Collateral Agent and PNC Capital Markets, Inc., as
Arranger. (Incorporated by reference to Exhibit 10.2 of the
Company's Current Report on Form 8-K dated February 27, 2002, File
1-8038).
10.43 Indenture dated as of February 22, 2002 among the Registrant and
U.S. Bank National Association. (Incorporated by reference to
Exhibit 4.1 of the Company's Current Report on Form 8-K dated
February 27, 2002, File 1-8038).
10.44 First Supplemental Indenture dated as of March 1, 2002 among the
Registrant, the Guarantors (as defined therein) and U.S. Bank
National Association. (Incorporated by reference to Exhibit 4.1 of
the Company's Current Report on Form 8-K dated March 1, 2002, File
1-8038).
10.45 Employment Agreement between Key Energy Services, Inc. and Thomas
K. Grundman dated February 15, 2002. (Incorporated by reference to
Exhibit 10.3 of the Company's Quarterly Report on Form 10-Q dated
March 31, 2002, File 1-8038).
*10.46 Separation and Release Agreement between Key Energy Services, Inc.
and Thomas K. Grundman dated May 6, 2002.
10.47 Plan and Agreement of Merger among Key Energy Services, Inc., Key
Merger Sub., Inc. and Q Services, Inc. dated as of May 13, 2002.
(Incorporated by reference to Exhibit 2.1 of the Company's Current
Report on Form 8-K dated May 17, 2002, File 1-8038).
*21 Significant Subsidiaries of the Company.
*23 Consent of KPMG LLP.
------------------------25.1 Statement of Eligibility of Trustee, U.S. Bank National
Association, a national banking association, on Form T-1.
(Incorporated by reference to Exhibit 25.1 of the Company's
Quarterly Report on Form 8-K dated February 27, 2002,
File 1-8038).
*99.1 Certification of CEO and CFO Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
(b) Reports on Form 8-K
The Company did not file anyfiled the following reports on Form 8-K during the quarter
ended June 30, 2001.2002:
(i) Current report on Form 8-K dated May 17, 2002 filed to report
the signing of a definitive merger agreement with Q Services,
Inc. dated as of May 13, 2002.
- -----------
* Filed herewith.
6765
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
and Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
KEY ENERGY SERVICES, INC.
(Registrant)
Dated: September 25, 2001 By: /s/ FRANCIS D. JOHN
-----------------------------------------KEY ENERGY SERVICES, INC.
(Registrant)
Dated: September 30, 2002 By: /s/ FRANCIS D. JOHN
----------------------------------
Francis D. John
CHAIRMAN OF THE BOARD, PRESIDENT,
AND CHIEF EXECUTIVE OFFICER
Pursuant to the requirements of the Securities and Exchange Act of
1934, this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Dated: September 25, 2001 By: /s/ FRANCIS D. JOHN
-----------------------------------------
Francis D. John
CHAIRMAN OF THE BOARD, PRESIDENT,
AND CHIEF EXECUTIVE OFFICER
Dated: September 25, 2001 By: /s/ THOMAS K. GRUNDMAN
-----------------------------------------
Thomas K. Grundman
CHIEF FINANCIAL OFFICER
AND CHIEF ACCOUNTING OFFICER
Dated: September 25, 2001 By: /s/ MORTON WOLKOWITZ
-----------------------------------------
Morton Wolkowitz
DIRECTOR
Dated: September 25, 2001 By: /s/ DAVID J. BREAZZANO
-----------------------------------------
David J. Breazzano
DIRECTOR
Dated: September 25, 2001 By: /s/ WILLIAM MANLY
-----------------------------------------
William Manly
DIRECTOR
Dated: September 25, 2001 By: /s/ KEVIN P. COLLINS
-----------------------------------------
Kevin P. Collins
DIRECTOR
Dated: September 25, 2001 By: /s/ W. PHILLIP MARCUM
-----------------------------------------
W. Phillip Marcum
DIRECTOR
Dated: September 25, 2001 By: /s/ WILLIAM D. FERTIG
-----------------------------------------Dated: September 30, 2002 By: /s/ FRANCIS D. JOHN
----------------------------------
Francis D. John
CHAIRMAN OF THE BOARD, PRESIDENT,
AND CHIEF EXECUTIVE OFFICER
Dated: September 30, 2002 By: /s/ ROYCE W. MITCHELL
----------------------------------
Royce W. Mitchell
CHIEF FINANCIAL OFFICER
AND CHIEF ACCOUNTING OFFICER
Dated: September 30, 2002 By: /s/ MORTON WOLKOWITZ
----------------------------------
Morton Wolkowitz
DIRECTOR
Dated: September 30, 2002 By: /s/ DAVID J. BREAZZANO
----------------------------------
David J. Breazzano
DIRECTOR
Dated: September 30, 2002 By: /s/ KEVIN P. COLLINS
----------------------------------
Kevin P. Collins
DIRECTOR
Dated: September 30, 2002 By: /s/ W. PHILLIP MARCUM
----------------------------------
W. Phillip Marcum
DIRECTOR
Dated: September 30, 2002 By: /s/ WILLIAM D. FERTIG
----------------------------------
William D. Fertig
DIRECTOR
Dated: September 30, 2002 By: /s/ J. ROBINSON WEST
----------------------------------
J. Robinson West
DIRECTOR
66
I, Francis D. John, certify that:
1. I have reviewed this annual report on Form 10-K of Key Energy Services,
Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report.
Date: September 30, 2002
/s/ FRANCIS D. JOHN
------------------------
Francis D. John
Chief Executive Officer
67
CERTIFICATIONS
I, Royce W. Mitchell, certify that:
1. I have reviewed this annual report on Form 10-K of Key Energy Services,
Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report.
Date: September 30, 2002
/s/ ROYCE W. MITCHELL
------------------------
Royce W. Mitchell
Chief Financial Officer
68
SCHEDULE II
KEY ENERGY SERVICES, INC.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
AS OF JUNE 30,
ADDITIONS
--------------------------------------------------------------------
BALANCE AT
BEGINNING OF CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF YEAR EXPENSES OTHER ACCOUNTS(A)ACCOUNTS(a) DEDUCTIONS END OF YEAR
----------------- -------------- -------- ----------------- ---------- -----------
(IN THOUSANDS)
Allowance for doubtful
accounts:
2001.............................. $3,189 $1,2632002......................... $4,082 $168 $ -- $- $281 $3,969
2001......................... 3,189 1,263 - 370 $4,082
2000..............................4,082
2000......................... 6,790 1,648 --- 5,249 3,189
1999.............................. 2,843 5,928 3,112 5,093 6,790
------------------------
(a) Additions to allowance for doubtful accounts established through purchase
accounting.
69