UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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 DECEMBER 31, 2002
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[ ] 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 1-7573
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PARKER DRILLING COMPANY
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(Exact name of registrant as specified in its charter)
<Table>
Delaware 73-0618660
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
</Table>
1401 Enclave Parkway, Suite 600, Houston, Texas 77077
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(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code (281) 406-2000
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Securities registered pursuant to Section 12(b) of the Act:
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<Table>
<Caption>
Title of each class Name of each exchange on which registered:
- ------------------------------------------------ ------------------------------------------
Common Stock, par value $.16 2/3 per share New York Stock Exchange
9.75% Senior Notes due 2006 New York Stock Exchange
10.125% Senior Notes due 2009 New York Stock Exchange
5.5% Convertible Subordinated Notes due 2004 New York Stock Exchange
</Table>
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 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. [ ]
Indicate by check mark whether the agreement is an accelerated filer (as
defined in Exchange Act Rule 12b2). Yes [X] No [ ]
The aggregate market value of our common stock held by non-affiliates on
June 30, 2002 was $287.6 million. At January 31, 2003, there were 92,793,349
shares of common stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF OUR DEFINITIVE PROXY STATEMENT FOR THE 2003
ANNUAL MEETING OF SHAREHOLDERS ARE INCORPORATED BY REFERENCE IN PART III
PARKER DRILLING COMPANY
TABLE OF CONTENTS
PART I Page No.
Item 1. Business 2
Item 2. Properties 9
Item 3. Legal Proceedings 14
Item 4. Submission of Matters to a Vote of Security Holders 15
Item 4A. Executive Officers 15
PART II
Item 5. Market for Registrant's Common Stock and
Related Stockholder Matters 17
Item 6. Selected Financial Data 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 19
Item 7A. Quantitative and Qualitative Disclosures about Market Risk 34
Item 8. Financial Statements and Supplementary Data 35
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 80
PART III
Item 10. Directors and Executive Officers of the Registrant 80
Item 11. Executive Compensation 81
Item 12. Security Ownership of Certain Beneficial Owners
and Management 81
Item 13. Certain Relationships and Related Transactions 81
Item 14. Controls and Procedures 81
PART IV
Item 15. Exhibits, Financial Statement Schedule and
Reports on Form 8-K 82
Signatures 90
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K contains certain statements that are "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934. These
statements may be made directly in this document, or may be "incorporated by
reference," which means the statements are contained in other documents filed by
the Company with the Securities and Exchange Commission. All statements included
in this document, other than statements of historical facts, that address
activities, events or developments that the Company expects, projects, believes
or anticipates will or may occur in the future are "forward-looking statements,"
including without limitation:
*future operating results,
*future rig utilization and rental tool activity,
*future capital expenditures and investments in the acquisition and
refurbishment of rigs and equipment,
*future sales of assets,
*repayment of debt,
*maintenance of the Company's revolver borrowing base, and
*expansion and growth of operations.
Forward-looking statements are based on certain assumptions and analyses
made by management of the Company in light of its experience and perception of
historical trends, current conditions, expected future developments and other
factors it believes are relevant. Although management of the Company believes
that its assumptions are reasonable based on current information available, they
are subject to certain risks and uncertainties, many of which are outside the
control of the Company. These risks and uncertainties include:
*worldwide economic and business conditions that adversely affect market
conditions and/or the cost of doing business,
*the pace of recovery in the U.S. economy and the demand for natural gas,
*fluctuations in the market prices of oil and gas,
*imposition of unanticipated trade restrictions,
*political instability,
*governmental regulations that adversely affect the cost of doing business,
*adverse environmental events,
*adverse weather conditions,
*changes in concentration of customer and supplier relationships,
*unexpected cost increases for upgrade and refurbishment projects,
*unanticipated cancellation of contracts by operators without cause,
*changes in competition, and
*other similar factors (some of which are discussed in this Form 10-K and
in documents referred to in this Form 10-K).
Because the forward-looking statements are subject to risks and
uncertainties, the actual results of operations and actions taken by the Company
may differ materially from those expressed or implied by such forward-looking
statements. These risks and uncertainties are referenced in connection with
forward-looking statements that are included from time to time in this document.
Each forward-looking statement speaks only as of the date of this Form 10-K, and
the Company undertakes no obligation to publicly update or revise any
forward-looking statement.
1
PART I
Item 1. BUSINESS
GENERAL DEVELOPMENT
Parker Drilling Company was incorporated in the state of Oklahoma in 1954
after having been established in 1934 by its founder, Gifford C. Parker. The
founder was the father of Robert L. Parker, chairman and a principal
stockholder, and the grandfather of Robert L. Parker Jr., president and chief
executive officer. In March 1976, the state of incorporation of the Company was
changed to Delaware through the merger of the Oklahoma Corporation into its
wholly owned subsidiary Parker Drilling Company, a Delaware corporation. Unless
otherwise indicated, the term "Company" refers to Parker Drilling Company
together with its subsidiaries and "Parker Drilling" refers solely to the
parent, Parker Drilling Company. We make available free of charge on our website
at www.parkerdrilling.com, or on the Securities and Exchange Commission website
at www.sec.gov, our annual reports on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and amendments to those reports as soon as
reasonably practicable after we electronically file such material with, or
furnish to, the Securities and Exchange Commission.
The Company is a leading worldwide provider of contract drilling and
drilling related services. Our primary operating areas include the transition
zones of the Gulf of Mexico, Nigeria and the Caspian Sea; the offshore waters of
the Gulf of Mexico and on land in international oil and gas producing regions.
In addition to operating in the Gulf of Mexico, the Company's rental tool
business operates in the U.S. land markets of Texas and the Rocky Mountain
region.
The Company's current marketed rig fleet of 79 rigs, consisting of 27 barge
drilling and workover rigs, seven offshore jackup rigs, four offshore platform
rigs and 41 land rigs, enables the Company to provide a variety of drilling
services to oil and gas operators in numerous locations around the world. The
Company's barge drilling and workover rig fleet is dedicated to transition zone
waters, which are generally defined as coastal waters having depths from five to
25 feet. The Company's offshore jackup rigs currently operate in the Gulf of
Mexico market and are capable of drilling in water depths from nine to 215 feet.
The Company's land rig fleet generally consists of premium and specialized deep
drilling rigs, with 35 of its 41 marketed land rigs capable of drilling to
depths of 10,000 feet or greater.
DRILLING OPERATIONS
General
The Company provides contract drilling services in the transition zones,
which are coastal waters including lakes, bays, rivers and marshes, of the Gulf
of Mexico, the Caspian Sea and Nigeria, where barge rigs are the primary source
of drilling and workover services. Barge rigs are utilized because of their
ability to carry drilling equipment on board and navigate in shallow waters up
to 25 feet where conventional jackup rigs are unable to operate. Barge rigs are
towed to a drilling location at which time the hull is submerged to the bottom
to provide stability before operations begin.
The Company's land drilling operations specialize in the drilling of
difficult wells, often in remote locations and/or harsh environments. Since
beginning operations in 1934, the Company has operated in 53 foreign countries
and throughout the United States, making it one of the most geographically
diverse land drilling contractors in the world. All of the company's land rigs
operate in international locations.
2
The Company's international land drilling operations have focused primarily
in the Latin America region, the Asia Pacific region and the Commonwealth of
Independent States (the former Soviet Union, referred to hereinafter as the
"CIS"). The Company's reputation and operational expertise has led operators to
look to the Company as a pioneer for the exploration of oil and gas in new
"frontiers" around the world. The Company was the first to enter China in 1980
and has continued to provide drilling services to this market. The Company was
also the first western drilling contractor to enter Russia in 1991 followed by
Kazakhstan in 1993, now one of the Company's most active markets.
International markets differ from the U.S. market in terms of competition,
nature of customers, equipment and experience requirements. The majority of
international drilling markets have one or more of the following
characteristics: (i) a small number of competitors; (ii) customers who typically
are major, large independent or foreign national oil companies; (iii) drilling
programs in remote locations with little infrastructure and/or harsh
environments requiring drilling equipment with a large inventory of spare parts
and other ancillary equipment; and (iv) difficult i.e. high pressure, deep or
geologically challenging wells requiring considerable experience to drill.
The Company has been one of the pioneers in arctic drilling services and
has considerable experience with the technology required to drill in these
ecologically sensitive areas. Although originally developed for the North Slope
of Alaska, this technological expertise in arctic drilling is an asset to the
Company in marketing its services to operators in international markets with
similar environmental considerations, such as the Caspian Sea, Western Siberia
and Sakhalin Island.
The Company has been active in managing drilling rigs owned by third
parties, generally oil companies that prefer to own the rig equipment but do not
have the technical expertise or labor resources to operate the rig. During 2002,
the Company operated project management contracts in five countries.
U.S. Barge Drilling and Workover
The Company's U.S. market for its barge drilling rigs is the transition
zones of the Gulf of Mexico, primarily in Louisiana and, to a lesser extent,
Alabama and Texas. This area historically has been the world's largest market
for shallow water barge drilling. The Company, with 22 drilling and workover
barges, is one of two companies with a significant presence in this market.
International Barge Drilling
The Company's international barge drilling operations are focused in the
transition zones of Nigeria and the Caspian Sea. Although commodity prices also
affect demand for international drilling, international markets typically are
more attractive than U.S. markets because the increased capital and equipment
requirements usually allow contractors to secure long-term contracts and higher
dayrates when compared with domestic drilling operations.
The Company is the leading provider of barge rigs in Nigeria, with four of
the eight rigs in this market. The Company has operated in Nigeria since 1996.
In addition, the Company owns and operates the world's largest Arctic barge rig
in the Caspian Sea.
3
Jackup Drilling
The Company has seven shallow water jackup rigs in the Gulf of Mexico.
While overall jackup utilization was slightly higher in 2002 than in 2001,
dayrates were significantly lower throughout the year.
Platform Drilling
The Company's fleet of platform rigs consists of four modular self-erecting
rigs. These platform rigs consist of drilling equipment and machinery arranged
in modular packages that are transported to and self-erected on fixed offshore
platforms owned by oil companies.
Latin America
The Company has 17 land rigs located in Colombia, Peru and Bolivia, plus
one rig that is stacked in Houston awaiting deployment. One of the Company's
major customers reduced its drilling program in Colombia during the second
quarter of 2002 and released three of the four Company rigs working for the
customer. In addition, the market in Bolivia was depressed throughout the year
as the Company had only one rig working during the early part of 2002. The
declining market in Bolivia was due in part to reduced demand for Bolivian
natural gas in Brazil. The Company had one rig working in Peru the last six
months of 2002.
Asia Pacific/Middle East/Africa
The Company has 14 land rigs located in the Asia Pacific, Middle East and
Africa drilling markets. Included are seven helicopter transportable rigs
located in this region which facilitate exploration in areas of difficult
access, like the mountainside and jungle terrain of Indonesia and Papua New
Guinea. This market had flat activity throughout the year.
CIS
Ten of the Company's rigs are currently located in the oil and gas
producing regions of the CIS. The Company was the first Western drilling
contractor to enter this market, in 1991, and it continued to be a major area of
operations in 2002. Two of the three rigs the Company leased to Saipar B.V., the
Company's joint venture with Saipem, a drilling subsidiary of Eni S.p.A., in
Kazakhstan's Karachaganak field, were released from contract in 2002. In the
Tengiz field in Kazakhstan, the Company operates through AralParker, a joint
venture with a local Kazakhstan company. In November 2002, the Company received
a notification from its customer that operations would be suspended after
completion of wells currently being drilled pending resolution of funding issues
among its partners. The suspension was lifted in early 2003, resulting in
minimal financial impact and negligible disruptions to the Company's drilling
operations. In Russia, the Company had one rig under contract throughout 2002,
and mobilized a new rig to Sakhalin Island. This rig was designed and built by
the Company and sold to the customer. Drilling operations under an operations
and maintenance contract with this customer are expected to commence in
mid-2003.
4
RENTAL TOOLS
Quail Tools, based in New Iberia, Louisiana, is a provider of premium
rental tools used for land and offshore oil and gas drilling and workover
activities. Approximately 65 percent of Quail's equipment is utilized in
offshore and coastal water operations. Since its inception in 1978, Quail's
principal customers have been major and independent oil and gas exploration and
production companies. Quail has facilities in New Iberia, Louisiana; Victoria,
Texas; Odessa, Texas and Evanston, Wyoming.
COMPETITION
The contract drilling industry is a competitive and cyclical business
characterized by high capital requirements and difficulty in finding and
retaining qualified field personnel.
In the Gulf of Mexico barge drilling and workover markets, the Company
competes with one major contractor. In the jackup and platform markets, there
are numerous U.S. offshore contractors. In international land markets, the
Company competes with a number of international drilling contractors but also
with smaller local contractors in certain markets. However, due to the high
capital costs of operating in international land markets as compared to the U.S.
land market, the high cost of mobilizing land rigs from one country to another,
and the technical expertise required, there are usually fewer competitors in
international land markets. In international land and offshore markets,
experience in operating in challenging environments and customer alliances have
been factors in the selection of the Company in certain cases, as well as the
Company's patented drilling equipment for remote drilling projects. The Company
believes that the market for drilling contracts, both land and offshore, will
continue to be highly competitive for the foreseeable future. Certain
competitors have greater financial resources than the Company, which may enable
them to better withstand industry downturns, compete more effectively on the
basis of price, build new rigs or acquire existing rigs.
Management believes that Quail Tools is one of the leading rental tool
companies in the offshore Gulf of Mexico and the Gulf Coast land markets. Some
of Quail's competitors are substantially larger and have greater financial
resources than Quail Tools.
CUSTOMERS
The Company believes it has developed a reputation for providing efficient,
safe, environmentally conscious and innovative drilling services. An increasing
trend indicates that a number of the Company's customers have been seeking to
establish exploration or development drilling programs based on partnering
relationships or alliances with a limited number of preferred drilling
contractors. Such relationships or alliances can result in longer-term work and
higher efficiencies that increase profitability for drilling contractors at a
lower overall well cost for oil and gas operators. The Company is currently a
preferred contractor for operators in certain United States and international
locations, which management believes is a result of the Company's quality of
equipment, personnel, safety records, service and experience.
The Company's drilling and rental tool customer base consists of major,
independent and foreign-owned oil and gas companies. For fiscal year 2002 and
2001 respectively, ChevronTexaco was the Company's largest customer with
approximately 17 percent of total revenues in 2002 and 15 percent in 2001. In
2002, Tengizchevroil ("TCO"), a joint venture with four oil companies, was the
second largest customer with 13 percent of total revenues. Shell Petroleum
Development Company of Nigeria was the Company's largest customer for 2000 with
approximately 10 percent of total revenues.
5
CONTRACTS
The Company generally obtains contracts through competitive bidding. Under
most contracts the Company is paid a daily fee, or dayrate. The dayrate received
is based on several factors, including, type of equipment, services and
personnel furnished, investment required to perform the contract, location of
the well, term of the contract, and competition.
The Company generally receives a lump sum fee to move its equipment to the
drilling site, which in most cases approximates the cost incurred by the
Company. U.S. contracts are generally for one to three wells with options to
drill additional wells, while international contracts are more likely to be for
multi-well long-term programs.
Rental tool contracts are typically on a dayrate basis with rates based on
type of equipment, investment and competition.
EMPLOYEES
At December 31, 2002, the Company employed 2,898 people, a decrease of 21
percent from the 3,654 employed at December 31, 2001. The following table sets
forth the composition of the Company's employees.
December 31,
-----------------------
2002 2001
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International drilling operations 1,748 2,444
U.S. drilling operations 834 878
Rental tool operations 135 140
Corporate and other 181 192
----- -----
Total employees 2,898 3,654
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RISKS AND ENVIRONMENTAL CONSIDERATIONS
The operations of the Company are subject to numerous federal, state and
local laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. Numerous
governmental agencies, such as the U.S. Environmental Protection Agency ("EPA"),
issue regulations to implement and enforce such laws, which often require
difficult and costly compliance measures that carry substantial administrative,
civil and criminal penalties or may result in injunctive relief for failure to
comply. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentrations of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit construction or drilling
activities on certain lands lying within wilderness, wetlands, ecologically
sensitive and other protected areas, require remedial action to prevent
pollution from former operations, and impose substantial liabilities for
pollution resulting from the Company's operations. Changes in environmental laws
and regulations occur frequently, and any changes that result in more stringent
and costly compliance could adversely affect the Company's operations and
financial position, as well as those of similarly situated entities operating in
the Gulf Coast market. While management believes that the Company is in
substantial compliance with current applicable environmental laws and
regulations, there is no assurance that compliance can be maintained in the
future.
6
The drilling of oil and gas wells is subject to various federal, state,
local and foreign laws, rules and regulations. The Company, as an owner or
operator of both onshore and offshore facilities including mobile offshore
drilling rigs in or near waters of the United States, may be liable for the
costs of removal and damages arising out of a pollution incident to the extent
set forth in the Federal Water Pollution Control Act, as amended by the Oil
Pollution Act of 1990 ("OPA"), the Outer Continental Shelf Lands Act ("OCSLA"),
the Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), and the Resource Conservation and Recovery Act ("RCRA"), each as
amended from time to time. In addition, the Company may also be subject to
applicable state law and other civil claims arising out of any such incident.
The OPA and regulations promulgated pursuant thereto impose a variety of
regulations on "responsible parties" related to the prevention of oil spills and
liability for damages resulting from such spills. A "responsible party" includes
the owner or operator of a vessel, pipeline or onshore facility, or the lessee
or permittee of the area in which an offshore facility is located. The OPA
assigns liability of oil removal costs and a variety of public and private
damages to each responsible party.
The liability for a mobile offshore drilling rig is determined by whether
the unit is functioning as a vessel or is in place and functioning as an
offshore facility. If operating as a vessel, liability limits of $600 per gross
ton or $500,000, whichever is greater, apply. If functioning as an offshore
facility, the mobile offshore drilling rig is considered a "tank vessel" for
spills of oil on or above the water surface, with liability limits of $1,200 per
gross ton or $10.0 million. To the extent damages and removal costs exceed this
amount, the mobile offshore drilling rig will be treated as an offshore facility
and the offshore lessee will be responsible up to higher liability limits for
all removal costs plus $75.0 million. A party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Few defenses exist to the
liability imposed by the OPA. The OPA also imposes ongoing requirements on a
responsible party, including proof of financial responsibility (to cover at
least some costs in a potential spill) and preparation of an oil spill
contingency plan for offshore facilities and vessels in excess of 300 gross
tons. Amendments to the OPA adopted in 1996 require owners and operators of
offshore facilities that have a worst case oil spill potential of more than
1,000 barrels to demonstrate financial responsibility in amounts ranging from
$10.0 million in specified state waters to $35.0 million in federal Outer
Continental Shelf waters, with higher amounts, up to $150.0 million, in certain
limited circumstances where the U.S. Minerals Management Service ("MMS")
believes such a level is justified by the risks posed by the quantity or quality
of oil that is handled by the facility. However, such OPA amendments did not
reduce the amount of financial responsibility required for "tank vessels." Since
the Company's offshore drilling rigs are typically classified as tank vessels,
the recent amendments to the OPA are not expected to have a significant effect
on the Company's operations. A failure to comply with ongoing requirements or
inadequate cooperation in a spill may even subject a responsible party to civil
or criminal enforcement actions.
In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating on the
Outer Continental Shelf. Specific design and operational standards may apply to
Outer Continental Shelf vessels, rigs, platforms, vehicles and structures.
Violations of environmentally related lease conditions or regulations issued
pursuant to the OCSLA can result in substantial civil and criminal penalties as
well as potential court injunctions curtailing operations and the cancellation
of leases. Such enforcement liabilities can result from either governmental or
citizen prosecution.
7
All of the Company's operating U.S. barge drilling rigs have zero-discharge
capabilities as required by law. In addition, in recognition of environmental
concerns regarding dredging of inland waters and permitting requirements, the
Company conducts negligible dredging operations, with approximately two-thirds
of the Company's offshore drilling contracts involving directional drilling,
which minimizes the need for dredging. However, the existence of such laws and
regulations has had and will continue to have a restrictive effect on the
Company and its customers.
CERCLA, also known as "Superfund," and comparable state laws impose
liability without regard to fault or the legality of the original conduct, on
certain classes of persons who are considered to be responsible for the release
of a "hazardous substance" into the environment. While CERCLA exempts crude oil
from the definition of hazardous substances for purposes of the statute, the
Company's operations may involve the use or handling of other materials that may
be classified as hazardous substances. CERCLA assigns strict liability to each
responsible party for all response and remediation costs, as well as natural
resource damages. Few defenses exist to the liability imposed by CERCLA. The
Company believes that it is in compliance with CERCLA and currently is not aware
of any events that, if brought to the attention of regulatory authorities, would
lead to the imposition of CERCLA liability against the Company.
RCRA generally does not regulate most wastes generated by the exploration
and production of oil and gas. RCRA specifically excludes from the definition of
hazardous waste "drilling fluids, produced waters, and other wastes associated
with the exploration, development, or production of crude oil, natural gas or
geothermal energy." However, these wastes may be regulated by EPA or state
agencies as solid waste. Moreover, ordinary industrial wastes, such as paint
wastes, waste solvents, laboratory wastes, and waste oils, may be regulated as
hazardous waste. Although the costs of managing solid and hazardous wastes may
be significant, the Company does not expect to experience more burdensome costs
than similarly situated companies involved in drilling operations in the Gulf
Coast market.
The drilling industry is dependent on the demand for services from the oil
and gas exploration and development industry, and accordingly, is affected by
changes in laws relating to the energy business. The Company's business is
affected generally by political developments and by federal, state, local and
foreign regulations that may relate directly to the oil and gas industry. The
adoption of laws and regulations, both U.S. and foreign, that curtail
exploration and development drilling for oil and gas for economic, environmental
and other policy reasons may adversely affect the Company's operations by
limiting available drilling opportunities.
8
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The Company operates in three segments, U.S. drilling operations,
international drilling operations and rental tools. Information about the
Company's business segments and operations by geographic areas for the years
ended December 31, 2002, 2001 and 2000 is set forth in Note 11 in the notes to
the consolidated financial statements.
Item 2. PROPERTIES
The Company leases office space in Houston for its corporate headquarters.
Additionally, the Company owns and leases office space and operating facilities
in various locations, but only to the extent necessary for administrative and
operational support functions. The Company owns a ten-story building in Tulsa,
Oklahoma, the previous corporate headquarters which is vacant and held for sale.
Land Rigs - The following table shows, as of December 31, 2002, the
locations and drilling depth ratings of the Company's 41 actively marketed land
rigs:
Drilling Depth Rating in Feet
---------------------------------------------------------------------
10,000 10,000
or to Over
International less 25,000 25,000 Total
- ------------------------------------------- --------------- --------------- --------------- --------------
Actively marketed land rigs:
Latin America - 13 5 18
Asia Pacific/Middle East/Africa 4 10 - 14
CIS 2 4 3 9
--------------- --------------- --------------- --------------
Total 6 27 8 41
=============== =============== =============== ==============
In addition, the Company has seven land rigs classified as cold stacked
which would need to be refurbished at a significant cost before being placed
back into service, with locations and drilling depth ratings as follows:
Drilling Depth Rating in Feet
---------------------------------------------------------------------
10,000 10,000
or to Over
International less 25,000 25,000 Total
- ------------------------------------------- --------------- --------------- --------------- --------------
Cold stacked land rigs:
Latin America - 1 - 1
Asia Pacific/Middle East/Africa 3 3 - 6
CIS - - - -
--------------- --------------- --------------- --------------
Total 3 4 - 7
=============== =============== =============== ==============
9
Barge Rigs - A schedule of the Company's deep, intermediate, and workover
and shallow drilling barge rigs located in the Gulf of Mexico, as of December
31, 2002, is set forth below:
Year Built Maximum
or Last Drilling
Gulf of Mexico Horsepower Refurbished Depth (Feet) Status (1)
- ------------------------------------------- --------------- --------------- ------------ --------------
Deep drilling:
Rig No. 15 1,000 1998 15,000 Active
Rig No. 50 2,000 2001 25,000 Active
Rig No. 51 2,000 1993 25,000 Active
Rig No. 53 1,600 1995 20,000 Active
Rig No. 54 2,000 1995 25,000 Active
Rig No. 55 2,000 2001 25,000 Active
Rig No. 56 2,000 1992 25,000 Active
Rig No. 57 1,500 1997 20,000 Active
Rig No. 76 3,000 1997 30,000 Active
Intermediate drilling:
Rig No. 8 1,000 1995 14,000 Active
Rig No. 17 1,000 1993 13,000 Active
Rig No. 20 1,000 2001 12,500 Active
Rig No. 21 1,200 2001 13,000 Active
Rig No. 23 1,000 1993 11,500 Active
Workover and shallow drilling:
Rig No. 6 (2) 700 1995 - Active
Rig No. 9 (2) 650 1996 - Active
Rig No. 12 1,100 1990 14,000 Active
Rig No. 16 800 1994 8,500 Active
Rig No. 18 800 1993 8,500 Active
Rig No. 24 1,000 1992 11,500 Active
Rig No. 25 1,000 1993 11,500 Active
Rig No. 26 (2) 650 1996 - Active
(1) "Active" denotes that the rig is currently under contract or
available for contract.
(2) Workover rig.
10
A schedule of the Company's international drilling barges, as of December
31, 2002, is set forth below:
Year Built Maximum
or Last Drilling
International Horsepower Refurbished Depth (Feet) Status (1)
- ------------------------------------------- --------------- --------------- -------------- --------------
Deep drilling:
Rig No. 72 3,000 2002 30,000 Active
Rig No. 73 3,000 2002 30,000 Active
Rig No. 74 3,000 1997 30,000 Active
Rig No. 75 3,000 1999 30,000 Active
Rig No. 257 3,000 1999 30,000 Active
(1) "Active" denotes that the rig is currently under contract or
available for contract.
Platform Rigs - The following table sets forth certain information, as of
December 31, 2002, with respect to the Company's platform rigs:
Year Built Maximum
or Last Drilling
Gulf of Mexico Horsepower Refurbished Depth (Feet) Status (1)
- ------------------------------------------- --------------- --------------- ------------ --------------
Platform rigs:
Rig No. 2 1,000 1981 12,000 Active
Rig No. 3 1,000 1995 12,000 Active
Rig No. 10 (2) 650 1982 - Active
Rig No. 41 1,000 1997 12,500 Active
(1) "Active" denotes that the rig is currently under contract or
available for contract.
(2) Workover rig.
11
Jackup Rigs - The following table sets forth certain information as of
December 31, 2002, with respect to the Company's jackup rigs:
Maximum Maximum
Water Drilling
Gulf of Mexico Design (1) Depth (Feet) Depth (Feet) Status (2)
- ----------------------------- --------------------------------------- --------------- --------------- ---------------
Jackup rigs:
Rig No. 11 (3) Bethlehem JU-200 (MC) 200 - Active
Rig No. 14 Baker Marine Big Foot (IS) 85 20,000 Active
Rig No. 15 Baker Marine Big Foot III (IS) 100 20,000 Active
Rig No. 20 Bethlehem JU-100 (MC) 110 25,000 Active
Rig No. 21 Baker Marine BMC-125 (MC) 120 20,000 Active
Rig No. 22 Le Tourneau Class 51 (MC) 173 15,000 Active
Rig No. 25 Le Tourneau Class 150-44 (IC) 215 20,000 Active
(1) IC--independent leg, cantilevered; IS--independent leg, slot;
MC--mat-supported, cantilevered.
(2) "Active" denotes that the rig is currently under contract or
available for contract.
(3) Workover rig.
12
The following table presents the Company's utilization rates, rigs
available for service and cold stacked rigs.
Year Ended December 31,
---------------------------------
Transition Zone Rig Data 2002 2001
- ---------------------------------------------------------- -------------- ---------------
U.S. barge deep drilling:
Rigs available for service (1) 9.0 9.0
Utilization rate of rigs available for service (2) 78% 93%
U.S. barge intermediate drilling:
Rigs available for service (1) 5.0 5.0
Utilization rate of rigs available for service (2) 38% 80%
U.S. barge workover and shallow drilling:
Rigs available for service (1) 8.0 8.0
Utilization rate of rigs available for service (2) 32% 53%
International barge drilling:
Rigs available for service (1) 5.0 5.0
Utilization rate of rigs available for service (2) 85% 97%
Offshore Rig Data
- ----------------------------------------------------------
Jackup rigs:
Rigs available for service (1) 7.0 7.0
Utilization rate of rigs available for service (2) 80% 78%
Platform rigs:
Rigs available for service (1) 4.0 4.0
Utilization rate of rigs available for service (2) 9% 47%
Land Rig Data
- ----------------------------------------------------------
International rigs:
Rigs available for service (1) 41.0 41.0
Utilization rate of rigs available for service (2) 42% 49%
Cold stacked rigs (1) 7.0 7.0
(1) The number of rigs is determined by calculating the number of
days each rig was in the fleet, e.g., a rig under contract or
available for contract for an entire year is 1.0 "rigs
available for service" and a rig cold stacked for one quarter
is 0.25 "cold stacked rigs." "Rigs available for service"
includes rigs currently under contract or available for
contract. "Cold stacked rigs" includes all rigs that are
stacked and would require significant refurbishment cost
before being placed back into service.
(2) Rig utilization rates are based on a weighted average basis
assuming 365 days availability for all rigs available for
service. Rigs acquired or disposed of have been treated as
added to or removed from the rig fleet as of the date of
acquisition or disposal. Rigs that are in operation or fully
or partially staffed and on a revenue-producing standby status
are considered to be utilized. Rigs under contract that
generate revenues during moves between locations or during
mobilization/demobilization are also considered to be
utilized.
13
Item 3. LEGAL PROCEEDINGS
On July 6, 2001, the Ministry of State Revenues of Kazakhstan ("MSR")
issued an Act of Audit to the Kazakhstan branch ("PKD Kazakhstan") of Parker
Drilling Company International Limited ("PDCIL"), a wholly owned subsidiary of
the Company, assessing additional taxes of approximately $29.0 million for the
years 1998-2000. The assessment consisted primarily of adjustments in corporate
income tax based on a determination by the Kazakhstan tax authorities that
payments by Offshore Kazakhstan International Operating Company, ("OKIOC"), to
PDCIL of $99.0 million, in reimbursement of costs for modifications to Rig 257,
performed by PDCIL prior to the importation of the drilling rig into Kazakhstan,
are income to PKD Kazakhstan, and therefore, taxable to PKD Kazakhstan. PKD
Kazakhstan filed an Act of Non-Agreement that such reimbursements should not be
taxable and requested that the Act of Audit be revised accordingly. In November
2001, the MSR rejected PKD Kazakhstan's Act of Non-Agreement, prompting PKD
Kazakhstan to seek judicial review of the assessment. On December 28, 2001, the
Astana City Court issued a judgment in favor of PKD Kazakhstan, finding that the
reimbursements to PDCIL were not income to PKD Kazakhstan and not otherwise
subject to tax based on the U.S.-Kazakhstan Tax Treaty. The MSR appealed the
decision of the Astana City Court to the Civil Panel of the Supreme Court, which
confirmed the decision of the Astana City Court that the reimbursements were not
income to PKD Kazakhstan in March 2002. Although the court agreed with the MSR's
position on certain minor issues, no additional taxes will be payable as a
result of this assessment. The MSR has until the end of March 2003 to appeal the
decision of the Civil Panel to the Supervisory Panel of the Supreme Court of
Kazakhstan. It may also reopen the case thereafter if material new evidence is
discovered. In addition, the Company has filed a petition with the U.S. Treasury
Department for competent authority review, which is a tax treaty procedure to
resolve disputes as to which country may tax income covered under the treaty.
The U.S. Treasury Department has granted our petition and has initiated
proceedings with the MSR which is ongoing.
The Company is a party to certain legal proceedings that have resulted from
the ordinary conduct of its business. In the opinion of the Company's
management, none of these proceedings is expected to have a material adverse
effect on the Company.
14
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to Parker Drilling Company security holders
during the fourth quarter of 2002.
Item 4A. EXECUTIVE OFFICERS
Officers are elected each year by the board of directors following the
annual meeting for a term of one year and until the election and qualification
of their successors. The current executive officers of the Company and their
ages, positions with the Company and business experience are presented below:
(1) Robert L. Parker, 79, chairman, joined the Company in 1948 and was
elected vice president in 1950. He was elected president in 1954 and
chief executive officer and chairman in 1969. Since 1991, he has held
only the position of chairman.
(2) Robert L. Parker Jr., 54, president and chief executive officer,
joined the Company in 1973 as a contract representative and was named
manager of U.S. operations later in 1973. He was elected a vice
president in 1973, executive vice president in 1976 and was named
president and chief operating officer in October 1977. In December
1991, he was elected chief executive officer.
(3) Robert F. Nash, 59, senior vice president and chief operating officer,
joined the Company in November 2001. Mr. Nash joined the Company
following a 26-year career with Halliburton, during which time he held
numerous senior management positions with responsibility for
operations, technical development, manufacturing, procurement,
inventory management and sales and marketing. He also has considerable
experience with mergers, acquisitions, divestitures and
reorganizations.
(4) James W. Whalen, 61, senior vice president and chief financial
officer, joined the Company in October 2002. Mr. Whalen served as
chief commercial officer for Coral Energy from February 1998 through
January 2000. From August 1992 until February 1998, he served as chief
financial officer for Tejas Gas Corporation. From August 1981 until
August 1992, he held several executive positions at Coastal
Corporation including senior vice president, finance.
(5) Thomas L. Wingerter, 50, vice president of operations, joined the
Company in 1979. In 1983 he was named contract manager for the Rocky
Mountain division. He was promoted to Rocky Mountain division manager
in 1984, a position he held until September 1991 when he was elected
vice president, North American region. In March 1999 he was appointed
vice president and general manager - North American operations. In
January 2001, he was appointed to his current position.
(6) W. Kirk Brassfield, 47, vice president and corporate controller,
joined the Company in March 1998 as corporate controller and chief
accounting officer. From 1991 through March 1998, Mr. Brassfield
served in various positions, including subsidiary controller and
director of financial planning of MAPCO Inc., a diversified energy
company. From 1979 through 1991, Mr. Brassfield served at the public
accounting firm, KPMG.
15
OTHER PARKER DRILLING COMPANY OFFICERS
(7) John R. Gass, 51, vice president of sales and contracts, joined the
Company in 1977 and has served in various management positions in the
Company's international divisions. In 1985, he became the division
manager of Africa and the Middle East. In 1987, he directed the
Company's core drilling operations in South Africa. In 1989, he was
promoted to international contract manager. In January 1996, he was
elected vice president, frontier areas and assumed his current
position in March 1999.
(8) Denis Graham, 53, vice president of engineering, joined the Company in
2000. Mr. Graham was the senior vice president of technical services
for Diamond Offshore Inc., an international offshore drilling
contractor. His experience with Diamond Offshore ranged from 1978
through 1999 in the areas of offshore drilling rig design, new
construction, conversions, marine operations, maintenance and
regulatory compliance.
(9) David W. Tucker, 47, treasurer and director of investor relations,
joined the Company in 1978 as a financial analyst and served in
various financial and accounting positions before being named chief
financial officer of the Company's wholly owned subsidiary, Hercules
Offshore Corporation, in February 1998. Mr. Tucker was elected
treasurer in 1999 and assumed the responsibilities of director of
investor relations in 2002.
16
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Parker Drilling Company common stock is listed for trading on the New York
Stock Exchange under the symbol "PKD". At the close of business on December 31,
2002, there were 2,790 holders of record of Parker Drilling common stock. Prices
on Parker Drilling's common stock for the years ended December 31, 2002 and
2001, were as follows:
2002 2001
-------------------------------- --------------------------------
Quarter High Low High Low
- ----------------- -------------- -------------- -------------- --------------
First $ 4.82 $ 3.10 $ 7.53 $ 4.75
Second 4.74 2.95 7.40 5.21
Third 3.50 1.40 6.29 2.25
Fourth 2.65 1.73 4.07 2.56
No dividends have been paid on common stock since February 1987.
Restrictions contained in Parker Drilling's existing bank revolving loan
facility prohibit the payment of dividends and the indenture for the Senior
Notes restricts the payment of dividends. The Company has no present intention
to pay dividends on its common stock in the foreseeable future because of the
restrictions noted.
17
Item 6. SELECTED FINANCIAL DATA (Dollars in Thousands Except Per Share Data)
Year Ended December 31,
--------------------------------------------------------------------------
2002 2001 2000 1999
---------------- ---------------- ---------------- ----------------
Revenues $ 389,946 $ 487,965 $ 376,349 $ 324,553
Net income (loss) $(114,054)(2) $ 11,059 $ (19,045)(1) $ (37,897)
Diluted earnings (loss) per share $ (1.23)(2) $ 0.12 $ (0.23)(1) $ (0.49)
Total assets $ 953,325 $ 1,105,777 $ 1,107,419 $1,082,743
Long-term debt $ 583,444 $ 587,165 $ 592,584 $ 648,577
Four Months
Ended Year Ended
December 31, August 31,
1998 1998
---------------- ----------------
Revenues $ 136,723 $ 481,223
Net income (loss) $ (14,633) $ 28,092
Diluted earnings (loss) per share $ (0.19) $ 0.36
Total assets $ 1,159,326 $ 1,200,544
Long-term debt $ 630,479 $ 630,090
(1) Loss before extraordinary gain was $(22,981) or $(0.28) per
share.
(2) Loss before the cumulative effect of change in accounting
principle related to the impairment of goodwill was $(40,910)
or $(0.44) per share.
18
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
Outlook and Overview
The year 2002 was marked by an overall decline in rig activity and cash
flow for the Company. The Company incurred a net loss of $40.9 million before
the cumulative effect of the change in accounting principle, compared to net
income of $11.1 million in 2001. Rig utilization, dayrates and rental activity
decreased substantially in the Company's Gulf of Mexico drilling markets,
continuing a trend that started in the fourth quarter of 2001. The Company's
international markets began to improve late in 2001, experiencing significantly
higher utilization in the fourth quarter, most notably in the Asia Pacific
region and Kazakhstan; however, these gains were partially offset in 2002 by
reduced drilling activity in Latin America, primarily Colombia and Bolivia, and
downtime due to barge rig inspections and refurbishments in Nigeria.
After reaching, during 2001, the highest levels of dayrates and utilization
since the fall of 1998, the Gulf of Mexico drilling market began to soften
during the fourth quarter of 2001. The reduction in drilling activity by
operators was in response to declining demand and prices for natural gas, due in
part to the economic recession in the United States. This reduced level of
activity continued through 2002 even as the price for crude oil and natural gas
increased, due to the lack of acceptable well prospects and funding issues. Due
to the reduction in drilling activity in 2002, barge rig utilization decreased
from 76 percent in 2001 to 49 percent in 2002. Utilization for the jackup rigs
increased during the second half of 2002 to 80 percent, slightly higher than the
78 percent in 2001. Negating the increase in utilization was a 44 percent
decline in average dayrates for 2002 as compared to 2001. The Company's rental
tool business experienced a similar reduction in activity beginning in late 2001
that continued throughout 2002. Rental tool revenues declined in 2002 by $18.1
million and profit margins decreased from 65 percent in 2001 to 54 percent in
2002.
Our drilling operations in the CIS, which includes Kazakhstan and Russia,
are a significant part of our current international operations and the Company
believes the region has potential for additional growth in the future. Since
1993, our operations in Kazakhstan have grown from providing labor to our
principal customer to owning or managing 11 drilling rigs for several operators.
In the last few years, the government of Kazakhstan has requested that vendors
incorporate local content into their operations to stimulate the development of
a local oil and gas service industry and the Kazakhstan economy. In order to
take advantage of the growth potential and remain a preferred vendor in
Kazakhstan, it was advantageous for us to partner with a local company. In June
2002, PDCIL entered into an agreement to sell two of its rigs in Kazakhstan, and
assign the contract associated with said rigs, to AralParker, a Kazakhstan joint
venture company owned 50 percent by PDCIL and 50 percent by a Kazakhstan
company, Aralnedra CJSC. The sales price for the rigs was $42.7 million, which
represented the fair market value according to an appraisal by an independent
third party appraiser. The purchase of the rigs by AralParker was financed by
Parker Drilling over a five-year period and is collateralized by a lien on the
rigs and a security interest in the five-year drilling contract and its
proceeds. The transaction closed on August 15, 2002. In addition, PDCIL will
lease a third rig to AralParker, and will operate the joint venture company
pursuant to a management and technical services contract. In light of the
Company's significant influence over the business affairs of AralParker, its
financial statements are consolidated with the Company's financial statements in
accordance with generally accepted accounting principles. Although Aralnedra
effectively owns 50 percent of the two rigs, PDCIL will receive approximately 90
percent of the cash flow generated by the current five-year drilling contract,
effective February 2002, through the proceeds of repayment of the loan and the
management and technical services contract.
19
OUTLOOK AND OVERVIEW (continued)
In November, 2002, the Company and AralParker received notification from
TCO to suspend drilling operations upon completion of wells being drilled in
Kazakhstan's Tengiz field pending agreement on funding issues facing the TCO
partners. On January 27, 2003, the Company and AralParker received notification
to resume normal drilling operations in the Tengiz field, except for a labor
contract on a TCO-owned rig. While we received notification of the suspension
in mid-November, the rigs and crews were instructed to continue drilling wells
in progress as of the date of the suspension notice. As a result, operations
continued at near normal operating rates throughout most of the suspension
period, resulting in a minimal financial impact to the Company and AralParker.
During 2002, cash flow from operations declined $82.8 million to $33.2
million due primarily to the reduced drilling and rental tool activity. In
response to the decrease in cash flow from operations, the Company significantly
reduced capital expenditures for 2002 to $45.2 million as compared to $122.0
million in 2001. As a result, the Company's cash position remained substantially
the same from 2001 to 2002. Management anticipates that working capital needs
and funds required for capital spending in 2003 will be met with cash provided
by operations. Based on anticipated cash requirements for capital spending of
approximately $50.0 million in 2003, it is management's current intention to
hold capital expenditures at this reduced level and to apply available free cash
flow to repay long-term debt. The amount of debt that can be repaid is dependent
on the results of operations and the proceeds from the sale of assets in 2003.
Should new opportunities requiring additional capital arise, that are not
contemplated in management's current capital expenditure budget, the Company
will utilize existing cash and short-term investments and, if necessary,
borrowings under its revolving credit facility. In addition, the Company may
seek project financing or equity participation from outside alliance partners or
customers. The Company cannot predict whether such financing or equity
participation would be available on terms acceptable to the Company.
During the Company's fourth quarter conference call with investors,
management confirmed its previously announced guidance for 2003 of a net loss
range of $0.14 to $0.18 per share. This estimate is based on management's belief
that both dayrates and utilization will increase modestly during the last three
quarters of the year on the basis that current prices and expected demand for
oil and gas will stimulate an increase in drilling activity. Also, during the
conference call the Company announced a plan to sell assets by mid-year. Though
the exact assets targeted for sale were not identified, management believes that
these assets targeted for sale will generate $200 million in net proceeds after
transaction fees and taxes, which will be used to reduce long-term debt. The
Company has retained an investment banker to assist with the sale of assets, but
has not entered into any sales agreements at this time. The guidance for 2003
does not reflect the impact of any asset sales.
20
RESULTS OF OPERATIONS (continued)
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001
- ---------------------------------------------------------------------
The Company recorded a net loss of $40.9 million, for the year ended
December 31, 2002 before the cumulative effect of a change in accounting
principle, compared to net income of $11.1 million for the year ended December
31, 2001. The change in accounting principle related to the Company's adoption
of Statement of Financial Accounting Standards ("SFAS") No. 142 "Goodwill and
Other Intangible Assets" resulted in recording the impairment of goodwill,
effective the first quarter of 2002 in the amount of $73.1 million.
Year Ended December 31,
-----------------------------------------------------------------------
2002 2001
--------------------------------- -----------------------------------
Drilling and rental revenues: (Dollars in Thousands)
U.S. drilling $113,478 29% $190,809 39%
International drilling 228,958 59% 231,527 48%
Rental tools 47,510 12% 65,629 13%
-------------- --------------- --------------- ----------------
Total drilling and rental revenues $389,946 100% $487,965 100%
============== =============== =============== ================
The Company's revenues decreased $98.0 million from $488.0 million in 2001
to $389.9 million for the year ended December 31, 2002. This reduction in
revenues was attributed to reduced drilling activity world-wide, most notably in
the Gulf of Mexico, due to the economic downturn in the United States and
increased inventories of oil and natural gas.
U.S drilling revenues decreased $77.3 million in 2002 to $113.5 million due
primarily to decreased dayrates for all U.S. offshore drilling rigs and reduced
utilization for the barge drilling rigs. The Gulf of Mexico market declined
significantly during the fourth quarter of 2001 and continued throughout 2002
due primarily to a reduction in drilling activity by operators. This reduction
in drilling activity was in response to declining demand and prices for natural
gas and the economic recession in the United States that began during mid-2001.
Although prices for natural gas have risen, uncertainty regarding the economy
and international issues has caused operators to be hesitant to significantly
increase drilling at this time. Revenues for the barge rigs and jackup rigs
decreased $40.1 million and $27.8 million, respectively, during the current year
as compared to 2001. Utilization for the barge rigs decreased from 76 percent in
2001 to 49 percent in 2002 with a 10 percent decrease in dayrates. The seven
jackup rigs experienced a 44 percent decrease in average dayrates during 2002 as
compared to 2001; utilization for the jackups remained relatively constant in
year-to-year comparisons. Revenues for the platform rigs decreased $9.4 million
to $1.6 million, as all four platform rigs were stacked the last three quarters
of 2002.
International drilling revenues decreased $2.6 million to $229.0 million in
the current year as compared to December 31, 2001. International land drilling
revenues increased $4.1 million to $155.6 million during 2002 as compared to
2001. The CIS and Asia Pacific region both increased revenues during 2002.
21
RESULTS OF OPERATIONS (continued)
Revenues in the CIS region increased $10.3 million in 2002. Revenues
increased $7.4 million in the Company's Tengiz operations in 2002 as compared to
2001 primarily due to increased utilization. Revenues from the Company's
interest in Saipar, B.V., the Company's joint venture with Saipem, a drilling
subsidiary of Eni S.p.A., operating in the Karachaganak field of Kazakhstan,
increased $6.2 million due to increased rig lease rates in 2002 and from early
termination fees for rigs released by the operator in July and December. The
early termination fees totaled $3.7 million. Currently the Company has one rig
working in the Karachaganak field. Revenues increased in the Asia Pacific region
by $7.4 million related primarily to increased utilization and dayrates in Papua
New Guinea. Additionally, the Company increased the number of labor contracts in
Kuwait from two rigs in 2001 to six rigs in 2002.
Latin America revenues decreased by $13.6 million in 2002 as compared to
2001. The decreases are primarily related to low utilization in Colombia and
Bolivia. During the fourth quarter of 2001, Colombia and Bolivia had six rigs
and one rig working, respectively. At December 31, 2002, Colombia had three rigs
working and Bolivia had no rig activity. In Colombia, we had four drilling rigs
working for a customer when the operator terminated all drilling activity in May
of 2002. Since then one rig has gone back to work for this particular customer.
We are currently marketing the rigs in Colombia and elsewhere in the world to
replace the terminated contracts. The drilling market in Bolivia, which
diminished significantly in mid-2001, showed no signs of recovery throughout
2002, primarily due to reduced demand for natural gas from Brazil. Contributing
to the reduced demand in 2002 are delays in receiving the Bolivian government's
commitment to a new gas pipeline to the west coast of South America to enable
the exporting of natural gas to Mexico and the United States. Revenues in
Bolivia decreased $9.7 million to $1.0 million in 2002.
International offshore drilling revenues decreased $6.7 million to $73.4
million when compared to 2001, primarily attributable to Nigeria. During the
second and third quarters, two of the Company's four barge rigs operating in
Nigeria incurred downtime for required American Bureau of Shipping ("ABS")
inspections and repairs that resulted in a combined total of five months with no
revenues. Shortly after returning to work the drilling contracts for these two
barge rigs concluded and only one contract has subsequently been renewed. At
December 31, 2002, three of the four barge rigs were drilling.
22
RESULTS OF OPERATIONS (continued)
Rental tool revenues decreased $18.1 million due to the decline in drilling
activity in the Gulf of Mexico and decreased land drilling in West Texas, which
reduced the demand for rental tools. Revenues decreased $9.1 million in the New
Iberia operations, $6.6 million in the Victoria, Texas, operations and $3.2
million from the Odessa, Texas, operations. Quail Tools opened a new operation
in Evanston, Wyoming, in July, 2002 which contributed $0.8 million in revenues
in 2002.
Year Ended December 31,
-----------------------------------------------------------------------
2002 2001
--------------------------------- -----------------------------------
Drilling and rental profit margins: (Dollars in Thousands)
U.S. drilling $ 27,654 24% $ 78,329 41%
International drilling 84,322 37% 77,043 33%
Rental tools 25,700 54% 42,624 65%
-------------- ---------------
Total drilling and rental profit margins 137,676 35% 197,996 41%
-------------- ---------------
Depreciation and amortization (98,503) (97,259)
Net construction contract operating income 2,462 -
General and administration expense (24,728) (21,721)
Provision for reduction in carrying value
of certain assets (1,500) -
Reorganization expense - (7,500)
-------------- ---------------
Total operating income $ 15,407 $ 71,516
============== ===============
(Drilling and rental profit margin - drilling and rental revenues less
direct drilling and rental operating expenses; drilling and rental
profit margin percentages - drilling and rental profit margin as a
percent of drilling and rental revenues.)
Profit margin of $137.7 million in the current period reflects a decrease
of $60.3 million from the $198.0 million recognized during the year ended
December 31, 2001. The U.S. and international drilling segments recorded profit
margin percentages of 24 percent and 37 percent, respectively, in 2002 as
compared to 41 percent and 33 percent in 2001. U.S. profit margins decreased
$50.7 million to $27.7 million for the year ended December 31, 2002 due to
declining revenues as discussed above. In response to declining revenues, U.S.
operations instituted cost controls for labor, materials and supplies. As a
result, the profit margin percentage increased during the fourth quarter to 34
percent from 28 percent during the third quarter on comparable revenues.
23
RESULTS OF OPERATIONS (continued)
International drilling profit margin increased $7.3 million to $84.3
million during the current year ended December 31, 2002 as compared to 2001.
International land drilling profit margin increased $11.2 million to $58.8
million. Profit margin in the CIS region increased $11.3 million with Kazakhstan
and Russia operations each increasing profit margin by approximately $5.7
million. The Kazakhstan increase is primarily attributable to increased
utilization in the Tengiz field and the early termination fees received for the
two rigs released that were previously operating in the Karachaganak field. The
profit margin increase in Russia is due to higher than anticipated mobilization
and start up costs incurred in 2001 that resulted in a significant loss. Asia
Pacific region's profit margin increased $2.6 million to $17.5 million during
the current year. Improvement in Asia Pacific is primarily related to increased
revenues in Papua New Guinea that resulted in increased profit margin of $2.3
million. Latin America's profit margin declined $2.7 million primarily due to
decreased drilling activity in Colombia and Bolivia. As noted previously,
revenues in Colombia and Bolivia decreased $14.0 million and $9.7 million,
respectively, for the year ended December 31, 2002 as compared to 2001. The
decreased profit margins in Colombia and Bolivia were partially offset by
increased profit margins in Ecuador and Peru. The contract in Ecuador was
completed in the third quarter of 2002 and the rig is currently stacked in
Houston. The contract in Peru will continue through 2003.
International offshore drilling profit margins decreased $4.0 million to
$25.5 million during the current year. This decrease in profit margin is
primarily attributed to Nigeria where two of the four barge rigs incurred a
combined total of five months downtime during the second and third quarters due
to ABS inspections and repairs. In addition, these two rigs both completed their
respective contracts toward the end of the third quarter and only one contract
was renewed in the fourth quarter. Currently the Company is operating three of
four barge rigs in Nigeria.
Rental tool profit margin decreased $16.9 million to $25.7 million during
2002 as compared to the year ended December 31, 2001. Profit margin decreased
primarily due to the $18.1 million decline in revenues during the current year.
The profit margin percentage decreased during the current year to 54 percent
from 65 percent for 2001 due to the significant fixed costs related to the
rental tool operation.
During the first quarter of 2002, the Company announced a new contract to
build and operate a rig to drill extended reach wells to offshore targets from a
land-based location on Sakhalin Island, Russia for an international consortium.
The revenue and expense for the project are recognized as construction contract
revenue and expense. The estimated profit from the engineering, construction,
mobilization and rig-up fees is calculated on a percentage of completion basis,
of which $2.5 million was recognized during the year ended December 31, 2002.
General and administrative expense increased $3.0 million to $24.7 million
for the year ended December 31, 2002. The increase is primarily due to severance
costs related to reductions in corporate personnel, significant increase in the
vacation accrual, professional fees and required maintenance on the former
corporate headquarters in Tulsa currently held for sale. With regards to the
vacation accrual the Company adopted a paid time off policy in 2002,
significantly increasing the required vacation accrual.
The $1.5 million provision for reduction in carrying value of certain
assets is to increase the allowance for doubtful accounts for a U.S. customer
who filed for bankruptcy protection during the second quarter of 2002. The $7.5
million of reorganization costs recorded in 2001 includes employee moving
expenses and severance costs related to the consolidation and relocation of the
Company's corporate and international drilling management to Houston, Texas,
from Tulsa, Oklahoma. The reorganization of certain senior management positions
and management of drilling operations accompanied the relocation.
24
RESULTS OF OPERATIONS (continued)
Interest expense decreased $0.6 million in 2002 compared to 2001. Savings
of $2.9 million associated with the three $50.0 million interest rate swap
agreements including $0.3 million from the amortization of gain on the
termination of the interest rate swap agreements were offset by $1.5 million
less interest capitalized and $0.6 million higher interest due to the higher
interest rate on the exchange notes. Other expense of $4.2 million for the year
ended December 31, 2002 includes $3.6 million related to the exchange offer (see
Note 6 of the notes to the consolidated financial statements) and $0.4 million
of costs incurred for the attempted purchase of Australia Oil and Gas.
Income tax expense for the year ended December 31, 2002 consists of foreign
tax expense of $21.3 million and a deferred tax benefit of $17.0 million.
Foreign taxes increased $7.4 million due primarily to $3.1 million paid during
the first quarter in Colombia related to a change in allowable depreciation in
the 2001 tax return and increased taxes in the Kazakhstan and the Asia Pacific
regions. The deferred tax benefit was recognized due to the loss generated
during the current year.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
- ---------------------------------------------------------------------
The Company recorded net income of $11.1 million, for the year ended
December 31, 2001, compared to a net loss of $23.0 million, before extraordinary
gain, recorded for the year ended December 31, 2000.
Year Ended December 31,
------------------------------------------
2001 2000
------------------- -------------------
Drilling and rental revenues: (Dollars in Thousands)
U.S. drilling $190,809 39% $148,416 40%
International drilling 231,527 48% 185,100 49%
Rental tools 65,629 13% 42,833 11%
-------- --- -------- ---
Total drilling and rental revenues $487,965 100% $376,349 100%
======== === ======== ===
The Company's revenues increased $111.6 million to $488.0 million in 2001
as compared to 2000. U.S. offshore drilling revenues increased $44.1 million to
$190.8 million due primarily to increased dayrates for the drilling barge rigs
and the jackup rigs. Dayrates increased 32 percent and 40 percent for the barge
rigs and jackup rigs, respectively, as compared to the previous year. The
increase in dayrates was partially offset by decreased utilization from 86
percent in 2000 to 78 percent in 2001 for the jackup rigs. The decrease in
utilization was due primarily to the slowdown in the Gulf of Mexico jackup
market during the fourth quarter of 2001. Jackup utilization during the fourth
quarter was 52 percent as compared to approximately 87 percent during the first
three quarters of 2001. U.S. land drilling revenues decreased $1.7 million due
to the sale of the Company's last remaining U.S. land rig, Rig 245, in November
2000.
25
RESULTS OF OPERATIONS (continued)
International drilling revenues increased $46.4 million to $231.5 million
in 2001 as compared to the year ended December 31, 2000. International land
drilling revenues increased $38.5 million to $151.5 million during 2001.
Revenues in the CIS region, which includes Kazakhstan and Russia, increased
$32.3 million to $63.1 million during 2001 as compared to the previous year.
Kazakhstan increased $30.0 million in 2001 as one rig was added to the Tengiz
operation and three rigs were added to the Karachaganak joint venture with
Saipem. Russia increased by $2.3 million as one rig commenced operations during
2001. Revenues increased $10.7 million in the Asia Pacific region due primarily
to increased rig utilization in Indonesia, Papua New Guinea and New Zealand.
Offsetting these increases were decreases in revenues from Madagascar and
Nigeria's land rig due to completion of drilling contracts in these countries in
2000. Revenues in the Latin America region decreased $4.4 million to $54.1
million during 2001. Revenues in Bolivia decreased $12.1 million during 2001 due
primarily to an oversupply of natural gas in Bolivia due to reduced demand for
Bolivian natural gas from Brazil, resulting in a significant decrease in rig
utilization. Partially offsetting the decrease in Bolivia was an increase in
revenues of $8.7 million in Colombia. During 2001 rig utilization increased in
Colombia to 92 percent from 83 percent in 2000.
International offshore drilling revenues increased $7.9 million to $80.0
million during 2001 as compared to 2000. Revenues in the Caspian Sea (barge Rig
257) decreased by $1.6 million while revenues in Nigeria increased $9.5 million.
Barge Rig 257 revenues decreased primarily due to reduced rates received during
the lengthy rig move after completion of the first well. Revenues for the four
barge rigs in Nigeria improved due to increased drilling operations on full
dayrates. In 2000 the rigs were on reduced standby rates for approximately six
months due to several episodes of community unrest.
Rental tool revenues increased $22.8 million in 2001 as compared to 2000
due to the increased level of drilling activity in the Gulf of Mexico.
Contributing to this increase was the New Iberia, Louisiana, operation in the
amount of $10.3 million, $6.3 million from the Victoria, Texas, operation and
$6.2 million from the Odessa, Texas, operation which commenced operations in May
2000.
<Table>
Year Ended December 31,
---------------------------------------------------------------
2001 2000
---------------------------- ---------------------------
(Dollars in Thousands)
Drilling and rental profit margins:
U.S. drilling $ 78,329 41% $ 49,219 33%
International drilling 77,043 33% 52,218 28%
Rental tools 42,624 65% 26,839 63%
--------- ---------
Total drilling and rental profit margins 197,996 41% 128,276 34%
--------- ---------
Depreciation and amortization (97,259) (85,060)
General and administration expense (21,721) (20,392)
Provision for reduction in carrying value
of certain assets - (8,300)
Reorganization expense (7,500) -
--------- ---------
Total operating income $ 71,516 $ 14,524
========= =========
(Drilling and rental profit margin - drilling and rental revenues less
direct drilling and rental operating expenses; drilling and rental
profit margin percentages - drilling and rental profit margin as a
percent of drilling and rental revenues.)
26
RESULTS OF OPERATIONS (continued)
Profit margin of $198.0 million in 2001 reflected an increase of $69.7
million from the $128.3 million recognized during the year ended December 31,
2000. The U.S. and international drilling segments recorded profit margin
percentages during 2001 of 41 percent and 33 percent, respectively, as compared
to 33 percent and 28 percent in 2000. U.S. profit margins increased $29.1
million. U.S. drilling profit margin was positively impacted during 2001 by
increasing dayrates in the Gulf of Mexico from the barge and jackup rigs.
Average dayrates for the barge rigs and jackup rigs increased approximately 31
percent and 42 percent, respectively, in 2001 as compared to the prior year.
Jackup rig utilization decreased from 86 percent in 2000 to 78 percent in 2001
due primarily to a slowdown in the Gulf of Mexico jackup market during the
fourth quarter, which resulted in jackup rig utilization of 52 percent. This
slowdown negatively impacted jackup rig dayrates, which declined approximately
23 percent from the first three quarters of 2001.
International drilling profit margin increased $24.8 million to $77.0
million during the year ended December 31, 2001 as compared to 2000.
International land drilling profit margin increased $18.1 million to $47.6
million. Profit margin for the international land drilling operations increased
in Kazakhstan from 33 percent to 45 percent, Papua New Guinea from 27 percent to
48 percent, and New Zealand from 20 percent to 39 percent, primarily due to
higher utilization during 2001. Profit margin in Russia decreased $5.4 million
due to higher than anticipated mobilization and start up costs. The
international offshore drilling profit margin increased $6.7 million to $29.5
million, with profit margin increasing from 32 percent to 37 percent during 2001
as compared to 2000.
Rental tool profit margin increased $15.8 million to $42.6 million during
2001 as compared to the year ended December 31, 2000. Profit margin increased
primarily due to the $22.8 million increase in revenues during 2001. The profit
margin percentage increased during 2001 to 65 percent from 63 percent for the
previous year due principally to higher revenues without a corresponding
increase in fixed cost.
Depreciation and amortization expense increased $12.2 million to $97.3
million in 2001. Depreciation expense recorded in connection with capital
additions for the years 1999, 2000 and 2001, was the primary reason for the
increase. General and administrative expenses increased $1.3 million in 2001 as
compared to 2000. This increase was primarily attributed to increased travel
costs, professional fees, information technology projects and higher occupancy
costs associated with the new corporate office in Houston.
The Company recognized $7.5 million in reorganization costs, which includes
employee-moving expenses and severance costs, during 2001. In September 2001,
the Company opened its new corporate office in Houston. The reorganization
included the consolidation of its corporate and international drilling
activities from Tulsa, Oklahoma, with its U.S. offshore drilling operations
already domiciled in Houston. The reorganization of certain senior management
positions and the management of drilling operations accompanied the relocation.
Interest expense decreased $4.0 million due to the $50.5 million repayment
of convertible notes during the fourth quarter of 2000 and $1.6 million of
interest being capitalized to construction projects during the year ended
December 31, 2001, as compared to $0.5 million capitalized during 2000. Gain on
disposition of assets decreased $15.6 million to $2.3 million for the year ended
December 31, 2001. During the year 2000, the Company sold its one million shares
of Unit Corporation common stock and recognized a pre-tax gain of $7.4 million
and the Company sold Rig 245 in Alaska for $20.0 million and recognized a
pre-tax gain of $14.9 million.
27
RESULTS OF OPERATIONS (continued)
Income tax expense for 2001 consists of foreign tax expense of $14.0
million and deferred tax benefit of $1.4 million. The deferred tax benefit is
due to the reduction in the valuation allowance of $9.6 million offsetting
deferred tax expense of $8.2 million. The reduction was the result of a change
in estimate relating to the realization of net operating loss carryforwards
(NOL's). At December 31, 2000, the Company carried a valuation account reserving
part of the NOL's set to expire during the tax year ended August 31, 2001. Due
to higher than projected taxable income for the 2001 tax year, the Company
utilized more NOL's than originally anticipated resulting in the deferred tax
benefit. As of December 31, 2001, the remaining valuation allowance is $9.9
million. For additional information, see Note 7 in the notes to the consolidated
financial statements.
LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 2002, the Company had cash and cash equivalents of $52.0
million, a decrease of $8.4 million from December 31, 2001. The net cash
provided by operating activities as reflected on the Consolidated Statement of
Cash Flows was $33.2 million for 2002. Due to reduced revenues during 2002,
accounts and notes receivable decreased $8.9 million. Lower utilization and
reduced capital spending resulted in a decrease of $19.8 million to accounts
payable and accrued liabilities.
Net cash used in investing activities was $38.7 million. This included
$45.2 million for capital expenditures net of proceeds from the sale of assets
of $6.5 million. Net cash used in financing activities was $2.9 million. This
included $5.5 million repayment of debt net of $2.6 million proceeds from the
settlement of three interest rate swap agreements.
As of December 31, 2001, the Company had cash and cash equivalents of $60.4
million, a decrease of $2.9 million from December 31, 2000. The primary sources
of cash in 2001, as reflected on the Consolidated Statement of Cash Flows, were
$116.0 million provided by operating activities and $7.6 million from the
disposition of assets. Proceeds from the disposition of assets included the sale
of various non-marketable rigs and components and reimbursements from customers
for equipment lost in the hole.
The primary uses of cash in 2001 were $122.0 million for capital
expenditures and $5.0 million for repayment of debt. Major projects during the
year included modifications to jackup Rig 22 as a result of its scheduled
five-year Coast Guard inspection, completion of Rig 216 to work in the
Karachaganak field in Kazakhstan, and purchase of drill pipe and other rental
tools for Quail. Repayment of debt included $4.5 million on a five-year note
with Boeing Capital Corporation for barge Rig 75 in Nigeria.
The Company has total long-term debt, including the current portion, of
$589.9 million at December 31, 2002. The Company has a $50.0 million revolving
credit facility with a group of banks led by Bank of America. This facility is
available for working capital requirements, general corporate purposes and to
support letters of credit. The revolver is collateralized by accounts
receivable, inventory and certain barge rigs located in the Gulf of Mexico. The
facility contains customary affirmative and negative covenants. Availability
under the revolving credit facility is subject to certain borrowing base
limitations based on 80 percent of eligible receivables plus 50 percent of
supplies in inventory, less the amount utilized in support of letters of credit.
Currently, the borrowing base of $41.2 million is reduced by $15.7 million in
outstanding letters of credit, resulting in available revolving credit of $25.5
million. As of December 31, 2002 no amounts have been drawn down against the
revolving credit facility. The revolver terminates on October 22, 2003. The
Company expects to renew or replace the revolving loan facility by the end of
the third quarter of 2003.
28
LIQUIDITY AND CAPITAL RESOURCES (continued)
The Company anticipates that funds required for capital spending in 2003
will be met from existing cash and cash provided by operations. It is
management's present intention to limit capital spending, net of reimbursements
from customers, to approximately $50 million in 2003. Should new drilling
projects or other opportunities requiring additional capital arise, or should
revenues not meet management's expectations, the Company may utilize the
revolving credit facility. In addition, the Company may seek project financing
or equity participation from outside alliance partners or customers to fund
certain capital projects. The Company cannot predict whether such financing or
equity participation would be available on terms acceptable to the Company.
The Company is exposed to interest rate risk from its fixed-rate debt. The
Company had hedged against the risk of changes in the fair value associated with
its 9.75% Senior Notes by entering into three fixed-to-variable interest rate
swap agreements with a total notional amount of $150.0 million. For the year
ended December 31, 2002, the interest rate swap agreements reduced interest
expense by $2.9 million.
On July 24, 2002, the Company terminated all the interest rate swap
agreements and received $3.5 million. A gain totaling $2.6 million will be
recognized as a reduction to interest expense over the remaining term (ending
November 2006) of the debt instrument, of which $0.3 million was recognized
during 2002.
See Note 4 of the notes to the consolidated financial statements for
information regarding the Company's exchange offer which was completed May 2,
2002.
29
LIQUIDITY AND CAPITAL RESOURCES (continued)
The following tables summarize the Company's future contractual obligations
and other commercial commitments as of December 31, 2002.
After 5
1 Year 2 - 3 Years 4 - 5 Years Years Total
-------- ----------- ---------- -------- --------
(Dollars in Thousands)
Contractual cash obligations:
Long-term debt (1) $ 6,486 $129,565 $214,192 $235,612 $585,855
Operating leases (2) 3,317 4,301 3,643 2,145 13,406
-------- -------- -------- -------- --------
Total contractual cash obligations $ 9,803 $133,866 $217,835 $237,757 $599,261
======== ======== ======== ======== ========
Commercial commitments:
Revolving credit facility (3) $ - $ - $ - $ - $ -
Standby letters of credit (3) 15,667 - - - 15,667
-------- -------- -------- -------- --------
Total commercial commitments $ 15,667 $ - $ - $ - $ 15,667
======== ======== ======== ======== ========
(1) Long-term debt includes the 9.75% Senior Notes, the 10.125%
Senior Notes, the 5.5% Convertible Subordinated Notes, the
secured 10.1278% promissory note and the capital lease. For
additional information, see Note 4 in the notes to the
consolidated financial statements.
(2) Operating leases consist of lease agreements in excess of one
year for office space, equipment, vehicles and personal
property. For additional information, see Note 12 in the notes
to the consolidated financial statements.
(3) The Company has available a $50.0 million revolving credit
facility. As of December 31, 2002, none has been drawn down,
but $15.7 million of availability has been used to support
letters of credit that have been issued. The revolving credit
facility expires in October 2003.
The Company does not have any unconsolidated special-purpose entities,
off-balance-sheet financing arrangements or guarantees of third-party financial
obligations. The Company has no energy or commodity contracts.
30
OTHER MATTERS
Business Risks
Internationally, the Company specializes in drilling geologically
challenging wells in locations that are difficult to access and/or involve harsh
environmental conditions. The Company's international services are primarily
utilized by major and national oil companies in the exploration and development
of reserves of oil. In the United States, the Company primarily drills offshore
in the Gulf of Mexico with barge, jackup and platform rigs for major and
independent oil and gas companies. Business activity is dependent on the
exploration and development activities of the major, independent and national
oil and gas companies that make up the Company's customer base. Generally,
temporary fluctuations in oil and gas prices do not materially affect these
companies' exploration and development activities, and consequently do not
materially affect the operations of the Company, except for the Gulf of Mexico,
where drilling contracts are generally for a shorter term, and oil and gas
companies tend to respond more quickly to upward or downward changes in prices.
Many international contracts are of longer duration and oil and gas companies
have committed to longer-term projects to develop reserves and thus our
international operations are not as susceptible to short term fluctuations in
prices. However, sustained increases or decreases in oil and natural gas prices
could have an impact on customers' long-term exploration and development
activities, which in turn could materially affect the Company's operations.
Generally, a sustained change in the price of oil would have a greater impact on
the Company's international operations while a sustained change in the price of
natural gas would have a greater effect on U.S. operations. Due to the locations
in which the Company drills, the Company's operations are subject to
interruption, prolonged suspension and possible expropriation due to political
instability and local community unrest. Further, the Company is exposed to
liability issues from pollution arising out of its operations and to loss of
revenues in the event of a blowout. The majority of the political and
environmental risks are transferred to the operator by contract or otherwise
insured.
Critical Accounting Policies
The Company considers certain accounting policies related to impairment of
property, plant and equipment, impairment of goodwill, the valuation of deferred
tax assets and revenue recognition to be critical accounting policies due to the
estimation processes involved in each. Other significant accounting policies are
summarized in Note 1 in the notes to the consolidated financial statements.
Impairment of property, plant and equipment - Management periodically
evaluates the Company's property, plant and equipment to determine that their
net carrying value is not in excess of their net realizable value. These
evaluations are performed when the Company has realized sustained significant
declines in utilization and dayrates and recovery is not contemplated in the
near future. Management considers a number of factors such as estimated future
cash flows, appraisals and current market value analysis in determining net
realizable value. Assets are written down to their fair value if it is below its
net carrying value.
Impairment of goodwill - Management periodically assesses whether the
excess of cost over net assets acquired is impaired based on the estimated fair
value of the operation to which it relates, which value is generally determined
based on estimated future cash flows of that operation. If the estimated fair
value is in excess of the carrying value of the operation, no further analysis
is performed. If the fair value of each operation, to which goodwill has been
assigned, is less than the carrying value, we will deduct the fair value of the
tangible and intangible assets and compare the residual amount to the carrying
value of the goodwill to determine if an impairment should be recorded.
31
OTHER MATTERS (continued)
In 2002, SFAS No. 142, "Goodwill and Other Intangible Assets," became
effective and as a result, the Company discontinued the amortization of $189.1
million of goodwill. The Company recorded $7.5 million of goodwill amortization
in 2001 and 2000 and would have recorded $7.5 million of goodwill amortization
during 2002. In lieu of amortization, the Company performed an initial
impairment review of goodwill and as a result impaired goodwill by $73.1
million. The Company will perform an annual impairment review, in December,
hereafter. The impairment was recognized as a cumulative effect of a change in
accounting principle. See Note 3 of the notes to the consolidated financial
statements for additional information.
Accounting for income taxes - As part of the process of preparing the
consolidated financial statements, the Company is required to estimate the
income taxes in each of the jurisdictions in which the Company operates. This
process involves estimating the actual current tax exposure together with
assessing temporary differences resulting from differing treatment of items,
such as depreciation, amortization and certain accrued liabilities for tax and
accounting purposes. These differences and the net operating loss carryforwards
result in deferred tax assets and liabilities, which are included within the
Company's consolidated balance sheet. The Company must then assess the
likelihood that the deferred tax assets will be recovered from future taxable
income, and to the extent the Company believes that recovery is not likely, the
Company must establish a valuation allowance. To the extent the Company
establishes a valuation allowance or increases or decreases this allowance in a
period, the Company must include an expense or reduction of expense within the
tax provision in the statement of operations.
Revenue recognition - The Company recognizes revenues and expenses on
dayrate contracts as the drilling progresses (percentage-of-completion method)
because the Company does not bear the risk of completion of the well. For
meterage contracts, the Company recognizes the revenues and expenses upon
completion of the well (completed-contract method). Revenues from rental
activities are recognized ratably over the rental term which is generally less
than six months.
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standard Board ("FASB") issued SFAS
No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002 and establishes an
accounting standard requiring the recording of the fair value of liabilities
associated with the retirement of long-term assets in the period in which the
liability is incurred. Accordingly, we adopted this standard in the first
quarter of 2003. We do not expect this standard to have a material impact on our
financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 was effective January
1, 2002. This statement supersedes SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and amends
Accounting Principles Board Opinion ("APB") No. 30 for the accounting and
reporting of discontinued operations, as it relates to long-lived assets. Our
adoption of SFAS No. 144 did not affect our financial position or results of
operations.
32
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 is effective for fiscal years beginning after May 15,
2002. We will adopt this standard in 2003 and do not expect it to have a
significant effect on our results of operations or our financial position.
In July 2002, the FASB issued SFAS No. 146, "Accounting For Costs
Associated with Exit or Disposal Activities." SFAS No. 146 is effective for exit
or disposal activities initiated after December 31, 2002. We do not expect the
adoption of this standard to have any impact on our financial position or
results of operations.
OTHER MATTERS (continued)
On December 31, 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure-An Amendment of SFAS No.
123." The standard provides additional transition guidance for companies that
elect to voluntarily adopt the accounting provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." SFAS No. 148 does not change the
provisions of SFAS No. 123 that permit entities to continue to apply the
intrinsic value method of APB No. 25, "Accounting for Stock Issued to
Employees." As we continue to follow APB No. 25, our accounting for stock-based
compensation will not change as a result of SFAS No. 148. SFAS No. 148 does
require certain new disclosures in both annual and interim financial statements.
The required annual disclosures are effective immediately and have been included
in Note 1 of the notes to the consolidated financial statements included in Item
8. The new interim disclosure provisions will be effective in the first quarter
of 2003.
In November 2002, the FASB issued FASB Interpretation ("FIN") 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantee of Indebtedness of Others." FIN 45 requires that upon
issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee. FIN 45's provisions for
initial recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The guarantor's previous
accounting for guarantees that were issued before the date of FIN 45's initial
application may not be revised or restated to reflect the effect of the
recognition and measurement provisions of the interpretation. The disclosure
requirements are effective for financial statements of both interim and annual
periods that end after December 15, 2002. The Company is not a guarantor under
any significant guarantees and thus this interpretation will not have a
significant effect on the Company's financial position or results of
operations.
On January 17, 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities, An Interpretation of Accounting Research Bulletin No. 51."
The primary objectives of FIN 46 are to provide guidance on how to identify
entities for which control is achieved through means other than through voting
rights (variable interest entities ("VIE")) and how to determine when and which
business enterprise should consolidate the VIE. This new model for consolidation
applies to an entity in which either (1) the equity investors do not have a
controlling financial interest or (2) the equity investment at risk is
insufficient to finance that entity's activities without receiving additional
subordinated financial support from other parties. See Note 1 of the notes to
the consolidated financial statements regarding our consolidation of AralParker,
a company in which we own a 50 percent equity interest. We are consolidating
this company because we exert significant influence and have a financial
interest in the form of a loan, in addition to our equity interest.
33
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
In December 2001, the Company began to utilize hedging strategies to manage
fixed-rate interest exposure by entering into one interest rate swap agreement.
In January 2002, the Company entered into two additional interest rate swap
agreements. The terms of the interest rate swap agreements are as follows:
Months Notional Amount Fixed Rate Floating Rate
- --------------------------------- ---------------------- -------------- --------------------------
(Dollars in Thousands)
December 2001 - November 2006 $ 50,000 9.75% Three-month LIBOR
plus 446 basis points
January 2002 - November 2006 $ 50,000 9.75% Three-month LIBOR
plus 475 basis points
January 2002 - November 2006 $ 50,000 9.75% Three-month LIBOR
plus 482 basis points
The Company assumed no ineffectiveness as each interest rate swap agreement
met the short-cut method requirements under SFAS No. 133 for fair value hedges
of debt instruments. As a result, changes in the fair value of the interest rate
swap agreements were offset by changes in the fair value of the debt and no net
gain or loss was recognized in earnings. During the year ended December 31,
2002, the interest rate swap agreements reduced interest expense by $2.9
million.
On July 24, 2002, the Company terminated all the interest rate swap
agreements and received $3.5 million. A gain totaling $2.6 million will be
recognized as a reduction to interest expense over the remaining term (ending
November 2006) of the debt instrument, of which $0.3 million was recognized
during 2002.
34
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
Parker Drilling Company
In our opinion, the consolidated financial statements listed in the index
appearing under Item 15(a)(1) of the Form 10-K, present fairly, in all material
respects, the financial position of Parker Drilling Company and its subsidiaries
at December 31, 2002 and 2001, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2002, in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement schedule listed in
the index appearing under Item 15(a)(2) of the Form 10-K, presents fairly, in
all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and financial statement schedule are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits. We
conducted our audits of these financial statements in accordance with auditing
standards generally accepted in the United States of America which 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, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
As discussed in Note 3 to the financial statements, in 2002, the Company
changed its method of accounting for goodwill as a result of adopting the
provisions of Statement of Financial Accounting Standards No. 142 "Goodwill and
Other Intangible Assets."
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
January 29, 2003
35
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Dollars in Thousands Except Per Share and Weighted Average Shares Outstanding)
Year Ended December 31,
------------------------------------------------
2002 2001 2000
------------ ------------ ------------
Drilling and rental revenues:
U.S. drilling $ 113,478 $ 190,809 $ 148,416
International drilling 228,958 231,527 185,100
Rental tools 47,510 65,629 42,833
------------ ------------ ------------
Total drilling and rental revenues 389,946 487,965 376,349
------------ ------------ ------------
Drilling and rental operating expenses:
U.S. drilling 85,824 112,480 99,197
International drilling 144,636 154,484 132,882
Rental tools 21,810 23,005 15,994
Depreciation and amortization 98,503 97,259 85,060
------------ ------------ ------------
Total drilling and rental operating expenses 350,773 387,228 333,133
------------ ------------ ------------
Drilling and rental operating income 39,173 100,737 43,216
------------ ------------ ------------
Construction contract revenue 86,818 - -
Construction contract expense 84,356 - -
------------ ------------ ------------
Net construction contract operating income 2,462 - -
------------ ------------ ------------
General and administration expense 24,728 21,721 20,392
Provision for reduction in carrying
value of certain assets 1,500 - 8,300
Reorganization expense - 7,500 -
------------ ------------ ------------
Total operating income 15,407 71,516 14,524
------------ ------------ ------------
Other income and (expense):
Interest expense (52,409) (53,015) (57,036)
Interest income 851 3,553 3,691
Gain on disposition of assets 3,432 2,316 17,920
Minority interest 278 - -
Other (4,169) (723) 2,243
------------ ------------ ------------
Total other income and (expense) (52,017) (47,869) (33,182)
------------ ------------ ------------
Income (loss) before income taxes (36,610) 23,647 (18,658)
Income tax expense 4,300 12,588 4,323
------------ ------------ ------------
Income (loss) before extraordinary gain and cumulative
effect of change in accounting principle (40,910) 11,059 (22,981)
Extraordinary gain on early retirement of debt,
net of deferred tax expense of $2,214 - - 3,936
Cumulative effect of change in accounting principle (73,144) - -
------------ ------------ ------------
Net income (loss) $ (114,054) $ 11,059 $ (19,045)
============ ============ ============
Basic earnings (loss) per share:
Income (loss) before extraordinary gain and
cumulative effect of change in accounting principle $ (0.44) $ 0.12 $ (0.28)
Extraordinary gain $ - $ - $ 0.05
Cumulative effect of change in accounting principle $ (0.79) $ - $ -
Net income (loss) $ (1.23) $ 0.12 $ (0.23)
Diluted earnings (loss) per share:
Income (loss) before extraordinary gain and
cumulative effect of change in accounting principle $ (0.44) $ 0.12 $ (0.28)
Extraordinary gain $ - $ - $ 0.05
Cumulative effect of change in accounting principle $ (0.79) $ - $ -
Net income (loss) $ (1.23) $ 0.12 $ (0.23)
Number of common shares used in computing earnings per share:
Basic 92,444,773 92,008,877 81,758,825
Diluted 92,444,773 92,691,033 81,758,825
See accompanying notes to the consolidated financial statements.
36
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
December 31,
-------------------------
ASSETS 2002 2001
- ----------------------------------------------------------- ---------- ----------
Current assets:
Cash and cash equivalents $ 51,982 $ 60,400
Accounts and notes receivable, net of allowance
for bad debts of $4,762 in 2002 and $2,988 in 2001 89,363 99,874
Rig materials and supplies 17,161 22,200
Other current assets 8,631 8,978
---------- ----------
Total current assets 167,137 191,452
---------- ----------
Property, plant and equipment, at cost:
Drilling equipment 1,099,211 1,063,454
Rental tools 81,325 74,085
Buildings, land and improvements 27,905 26,887
Other 31,371 25,606
Construction in progress 6,279 26,142
---------- ----------
1,246,091 1,216,174
Less accumulated depreciation and amortization 604,813 520,645
---------- ----------
Property, plant and equipment, net 641,278 695,529
---------- ----------
Deferred charges and other assets:
Goodwill, net of accumulated amortization of $108,412
in 2002 and $35,268 in 2001 115,983 189,127
Rig materials and supplies 9,450 9,201
Assets held for disposition 896 1,800
Debt issuance costs 6,330 8,247
Other 12,251 10,421
---------- ----------
Total deferred charges and other assets 144,910 218,796
---------- ----------
Total assets $ 953,325 $1,105,777
========== ==========
See accompanying notes to the consolidated financial statements.
37
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Continued)
(Dollars in Thousands)
December 31,
--------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY 2002 2001
- ----------------------------------------------------------- --------- -----------
Current liabilities:
Current portion of long-term debt $ 6,486 $ 5,007
Accounts payable 14,377 33,521
Accrued liabilities 36,365 38,152
Accrued income taxes 4,347 7,054
--------- -----------
Total current liabilities 61,575 83,734
--------- -----------
Long-term debt 583,444 587,165
Deferred income taxes - 16,152
Other long-term liabilities 7,680 6,583
Commitments and contingencies (Note 12)
Stockholders' equity:
Preferred stock, $1 par value, 1,942,000 shares
authorized, no shares outstanding - -
Common stock, $0.16 2/3 par value, authorized
140,000,000 shares, issued and outstanding
92,793,349 shares (92,053,796 shares in 2001) 15,465 15,342
Capital in excess of par value 434,998 432,845
Accumulated other comprehensive income-net unrealized
gain on investments available for sale (net of taxes of
$0 in 2002 and $227 in 2001) 664 403
Retained earnings (accumulated deficit) (150,501) (36,447)
--------- -----------
Total stockholders' equity 300,626 412,143
--------- -----------
Total liabilities and stockholders' equity $ 953,325 $ 1,105,777
========= ===========
See accompanying notes to the consolidated financial statements.
38
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31,
--------------------------------------
2002 2001 2000
--------- --------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $(114,054) $ 11,059 $(19,045)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation and amortization 98,503 97,259 85,060
Gain on disposition of assets (3,432) (2,316) (17,920)
Cumulative effect of change in accounting principle 73,144 - -
Gain on early retirement of debt, net of
deferred tax expense - - (3,936)
Provision for reduction in carrying value
of certain assets 1,500 - 8,300
Deferred tax expense (benefit) (17,120) (1,899) (11,302)
Other 6,045 4,625 5,320
Change in assets and liabilities:
Accounts and notes receivable 8,851 24,158 (47,954)
Rig materials and supplies 2,390 (3,807) (1,981)
Other current assets 347 (4,366) 11,150
Accounts payable and accrued liabilities (19,834) (4,484) 18,356
Accrued income taxes (1,843) (2,784) 1,098
Other assets (1,316) (1,440) 125
--------- --------- --------
Net cash provided by operating activities 33,181 116,005 27,271
--------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of assets 6,451 7,628 31,912
Capital expenditures (net of reimbursements) (45,181) (122,033) (98,525)
Proceeds from sale of short-term investments - 799 16,925
--------- --------- --------
Net cash used in investing activities (38,730) (113,606) (49,688)
--------- --------- --------
See accompanying notes to the consolidated financial statements.
39
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(Continued)
(Dollars in Thousands)
Year Ended December 31,
------------------------------------
2002 2001 2000
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from common stock offering, net $ - $ - $ 87,313
Payments for early retirement of debt - - (43,477)
Principal payments under debt obligations (5,489) (5,034) (4,854)
Proceeds from interest rate swap agreements 2,620 - -
Other - 555 414
-------- -------- --------
Net cash provided by (used in)
financing activities (2,869) (4,479) 39,396
-------- -------- --------
Net increase (decrease) in cash and cash equivalents (8,418) (2,080) 16,979
Cash and cash equivalents at beginning of year 60,400 62,480 45,501
-------- -------- --------
Cash and cash equivalents at end of year $ 51,982 $ 60,400 $ 62,480
======== ======== ========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest $ 52,532 $ 53,257 $ 56,608
Income taxes $ 19,454 $ 14,956 $ 14,527
Supplemental noncash investing and financing activity:
Net unrealized gain (loss) on investments
available for sale (net of taxes of $0 in 2002,
$37 in 2001 and $717 in 2000) $ 261 $ 64 $ (1,274)
Capital lease obligation $ 1,255 $ - $ -
See accompanying notes to the consolidated financial statements.
40
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(Dollars and Shares in Thousands)
Retained Accumulated
Capital in Earnings Other
Common Excess of (Accumulated Comprehensive
Shares Stock Par Value Deficit) Income (Loss)
-------- ------- ---------- ------------ -------------
Balances, December 31, 1999 77,372 $12,895 $343,374 $ (28,461) $ 1,613
Activity in employees' stock plans 552 92 2,656 - -
Issuance of 13,800,000
common shares 13,800 2,300 85,013 - -
Other comprehensive income-net
unrealized loss on investments
(net of taxes of $717) - - - - (1,274)
Net loss (total comprehensive
loss of $20,319) - - - (19,045) -
-------- ------- -------- --------- -------
Balances, December 31, 2000 91,724 15,287 431,043 (47,506) 339
Activity in employees' stock plans 330 55 1,802 - -
Other comprehensive income-net
unrealized gain on investments
(net of taxes of $37) - - - - 64
Net loss (total comprehensive
loss of $11,123) - - - 11,059 -
-------- ------- -------- --------- -------
Balances, December 31, 2001 92,054 15,342 432,845 (36,447) 403
Activity in employees' stock plans 739 123 2,153 - -
Other comprehensive income-net
unrealized gain on investments
(net of taxes of $0) - - - - 261
Net loss (total comprehensive
loss of $113,793) - - - (114,054) -
-------- ------- -------- --------- -------
Balances, December 31, 2002 92,793 $15,465 $434,998 $(150,501) $ 664
======== ======= ======== ========= =======
See accompanying notes to the consolidated financial statements.
41
PARKER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Significant Accounting Policies
Consolidation - The consolidated financial statements include the accounts
of Parker Drilling Company ("Parker Drilling") and all of its majority-owned
subsidiaries and a company in which a subsidiary of Parker Drilling has a 50
percent stock ownership but exerts significant influence over its operation. A
subsidiary of Parker Drilling also has a 50 percent interest in another company,
which is accounted for under the equity method (collectively, the "Company").
Operations - The Company provides land and offshore contract drilling
services and rental tools on a worldwide basis to major, independent and
foreign-owned oil and gas companies. At December 31, 2002, the Company's rig
fleet consists of 27 barge drilling and workover rigs, seven offshore jackup
rigs, four offshore platform rigs and 41 land rigs. The Company specializes in
the drilling of deep and difficult wells, drilling in remote and harsh
environments, drilling in transition zones and offshore waters, and in providing
specialized rental tools. The Company also provides a range of services that are
ancillary to its principal drilling services, including engineering and
logistics, as well as project management activities.
Drilling Contracts and Rental Revenues - The Company recognizes revenues
and expenses on dayrate contracts as the drilling progresses
(percentage-of-completion method) because the Company does not bear the risk of
completion of the well. For meterage contracts, the Company recognizes the
revenues and expenses upon completion of the well (completed-contract method).
Revenues from rental activities are recognized ratably over the rental term
which is generally less than six months.
Construction Contract - The Company has historically only constructed
drilling rigs for its own use. At the request of one of its significant
customers, the Company entered into a contract to design, construct, mobilize
and sell ("construction contract") a specialized drilling rig to drill extended
reach wells to offshore targets from a land-based location on Sakhalin Island,
Russia, for an international consortium of oil and gas companies. The Company
also entered into a contract to subsequently operate the rig on behalf of the
consortium. Generally Accepted Accounting Principles ("GAAP") requires that
revenues received and costs incurred related to the construction contract be
accounted for and reported on a gross basis and income for the related fees
should be recognized on a percentage of completion basis. Because this
construction contract is not a part of the Company's historical or normal
operations, the revenues and costs related to this contract have been shown as a
separate component in the statement of operations. Construction costs in excess
of funds received from the customer are accumulated and reported as part of
other current assets. At December 31, 2002 and 2001, a net receivable
(construction costs less progress payments) of $5.3 million and $6.0 million,
respectively, are included in other current assets.
Cash and Cash Equivalents - For purposes of the balance sheet and the
statement of cash flows, the Company considers cash equivalents to be all highly
liquid debt instruments that have a remaining maturity of three months or less
at the date of purchase.
42
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
Property, Plant and Equipment - The Company provides for depreciation of
property, plant and equipment primarily on the straight-line method over the
estimated useful lives of the assets after provision for salvage value. The
depreciable lives for land drilling equipment approximate 15 years. The
depreciable lives for offshore drilling equipment generally range from 15 to 20
years. The depreciable lives for certain other equipment, including drill pipe
and rental tools, range from three to seven years. Depreciable lives for
buildings and improvements range from 10 to 30 years. Interest totaling
approximately $0.1 million, $1.6 million and $0.5 million was capitalized during
the years ended December 31, 2002, 2001 and 2000, respectively. When properties
are retired or otherwise disposed of, the related cost and accumulated
depreciation are removed from the accounts and any gain or loss is included in
operations. Management periodically evaluates the Company's assets to determine
that their net carrying value is not in excess of their net realizable value.
Management considers a number of factors such as estimated future cash flows,
appraisals and current market value analysis in determining net realizable
value. Assets are written down to their fair value if it is below its net
carrying value.
Goodwill - Effective January 1, 2002, the Company adopted Statement of
Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible
Assets." In accordance with this accounting principle, goodwill is no longer
amortized but will be assessed for impairment on at least an annual basis (see
Note 3 for additional details regarding goodwill).
Rig Materials and Supplies - Since the Company's international drilling
generally occurs in remote locations, making timely outside delivery of spare
parts uncertain, a complement of parts and supplies is maintained either at the
drilling site or in warehouses close to the operations. During periods of high
rig utilization, these parts are generally consumed and replenished within a
one-year period. During a period of lower rig utilization in a particular
location, the parts, like the related idle rigs, are generally not transferred
to other international locations until new contracts are obtained because of the
significant transportation costs, which would result from such transfers. The
Company classifies those parts which are not expected to be utilized in the
following year as long-term assets. Rig materials and supplies are valued at the
lower of cost or market value.
Other Assets - Other assets include the Company's investment in marketable
equity securities. Equity securities that are classified as available for sale
are stated at fair value as determined by quoted market prices. Unrealized
holding gains and losses are excluded from current earnings and are included in
comprehensive income, net of taxes, in a separate component of stockholders'
equity until realized. At December 31, 2002 and 2001, the fair value of equity
securities totaled $1.3 million and $1.8 million, respectively.
In computing realized gains and losses on the sale of equity securities,
the cost of the equity securities sold is determined using the specific cost of
the security when originally purchased.
Other Long-Term Obligations - Included in this account is the accrual of
workers' compensation liability, which is not expected to be paid within the
next year.
Income Taxes - Deferred tax liabilities and assets are determined based on
the difference between the financial statement and tax basis of assets and
liabilities using enacted tax rates in effect for the year in which the
differences are expected to reverse.
43
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
Earnings (Loss) Per Share (EPS) - Basic earnings (loss) per share is
computed by dividing net income (loss), by the weighted average number of common
shares outstanding during the period. The effects of dilutive securities, stock
options and convertible debt are included in the diluted EPS calculation, when
applicable.
Concentrations of Credit Risk - Financial instruments, which potentially
subject the Company to concentrations of credit risk, consist primarily of trade
receivables with a variety of national and international oil and gas companies.
The Company generally does not require collateral on its trade receivables.
At December 31, 2002 and 2001, the Company had deposits in domestic banks
in excess of federally insured limits of approximately $51.6 million and $57.6
million, respectively. In addition, the Company had deposits in foreign banks at
December 31, 2002 and 2001 of $4.8 million and $3.5 million, respectively, which
are not federally insured.
The Company's drilling customer base consists of major, independent and
foreign-owned oil and gas companies. For fiscal year 2002 and 2001 respectively,
ChevronTexaco was the Company's largest customer with approximately 17 percent
of total revenues in 2002 and 15 percent in 2001. In 2002, Tengizchevroil, a
joint venture with four oil companies, was the second largest customer with 13
percent of total revenues. Shell Petroleum Development Company of Nigeria was
the Company's largest customer for 2000 with approximately 10 percent of total
revenues.
Derivative Financial Instruments - The Company adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended by
SFAS Nos. 137 and 138. These statements require that every derivative instrument
be recorded on the balance sheet as either an asset or liability measured by its
fair value. These statements also establish new accounting rules for hedge
transactions, which depend on the nature of the hedge relationship.
The Company uses derivative instruments to hedge exposure to interest rate
risk. For hedges which meet the SFAS No. 133 criteria, the Company formally
designates and documents the instrument as a hedge of a specific underlying
exposure, as well as the risk management objective and strategy for undertaking
each hedge transaction.
Fair Value of Financial Instruments - The carrying amount of the Company's
cash and cash equivalents and short-term and long-term debt had fair values that
approximated their carrying amounts, except for the Company's 5.5% Convertible
Subordinated Notes which had a carrying value of $124.5 million and a fair
market value of $115.3 million at December 31, 2002.
Stock-Based Compensation - The Company has elected the disclosure-only
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation."
Accordingly, no compensation cost has been recognized for the Company's stock
option plans when the option price is equal to or greater than the fair market
value of a share of the Company's common stock on the date of grant. Pro forma
net income and earnings per share are reflected in the following tables as if
compensation cost had been determined based on the fair value of the options at
their applicable grant date, according to the provisions of SFAS No. 123.
44
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
Year Ended December 31,
------------------------------------------
2002 2001 2000
---------- ---------- ----------
(Dollars in Thousands)
Income (loss) before extraordinary gain and cumulative
effect of change in accounting principle:
As reported $ (40,910) $ 11,059 $ (22,981)
Compensation expense, net of tax (2,597) (3,361) (2,960)
---------- ---------- ----------
Pro forma $ (43,507) $ 7,698 $ (25,941)
========== ========== ==========
Diluted earnings (loss) per share before extraordinary
gain and cumulative effect of change in accounting
principle:
As reported $ (0.44) $ 0.12 $ (0.28)
Compensation expense, net of tax (0.03) (0.04) (0.04)
---------- ---------- ----------
Pro forma $ (0.47) $ 0.08 $ (0.32)
========== ========== ==========
The fair value of each option grant is estimated using the Black-Scholes
option pricing model with the following assumptions:
Expected dividend yield 0.0%
Expected stock volatility 51.6% in 2000
56.3% in 2001
56.9% in 2002
Risk-free interest rate 3.0% - 6.7%
Expected life of options 5 - 7 years
Options granted in 2002, 2001 and 2000 under the 1997 Stock Plan had an
estimated fair value of $1,759,000, $4,326,000 and $203,000 respectively.
Accounting Estimates - The preparation of financial statements in
conformity with GAAP requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
45
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 2 - Disposition of Assets
On November 20, 2000, the Company sold its last remaining U.S. land rig,
Rig 245 in Alaska, for $20.0 million. The Company recognized a pre-tax gain of
$14.9 million during the fourth quarter of 2000.
Note 3 - Goodwill
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and
Other Intangible Assets." In accordance with this accounting principle, goodwill
is no longer amortized but will be assessed for impairment on at least an annual
basis.
As an initial step in the implementation process, the Company identified
four reporting units that would be tested for impairment. The four units qualify
as reporting units in that they are one level below an operating segment, or an
individual operating segment and discrete financial information exists for each
unit. The four reporting units identified by segment are as follows:
U.S. drilling segment: Barge rigs
Jackup and Platform rigs (1)
International drilling segment: Nigeria barge rigs
Rental tools segment: Rental tools business
(1) The jackup and platform rigs were aggregated due to the similarities in
the markets served.
As required under the transitional accounting provisions of SFAS No. 142,
the Company completed both steps required to identify and measure goodwill
impairment at each reporting unit. The first step involved identifying all
reporting units with carrying values (including goodwill) in excess of fair
value, which was estimated by an independent business valuation consultant using
the present value of estimated future cash flows. The reporting units for which
the carrying value exceeded fair value were then measured for impairment by
comparing the implied fair value of the reporting unit goodwill, determined in
the same manner as in a business combination, with the carrying amount of
goodwill. The jackup and platform rigs reporting unit was the only unit where
impairment was identified. As a result, goodwill related to the jackup and
platform rigs was impaired by $73.1 million and was recognized as a cumulative
effect of a change in accounting principle retroactive to the first quarter. The
Company will perform its annual impairment review during the fourth quarter of
each year. The review in the fourth quarter of 2002, resulted in no additional
impairment.
46
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 3 - Goodwill (continued)
The following is a summary of the change in goodwill by reporting unit for
the years ended December 31, 2000, 2001 and 2002 (dollars in thousands):
International
U.S. Drilling Drilling Rental Tools
Segment Segment Segment
--------------------------- ---------- ------------
Barge Jackup & Nigeria Rental Tools
Rigs Platform Rigs Barge Rigs Business
-------- ------------- ---------- ------------
Balance as of January 1, 2000 $ 63,110 $ 78,771 $ 23,198 $ 39,011
Goodwill amortization (2,367) (2,797) (864) (1,453)
Impairment losses - - - -
-------- ------------- ---------- ------------
Balance as of December 31, 2000 60,743 75,974 22,334 37,558
Goodwill amortization (2,334) (2,830) (863) (1,454)
Impairment losses - - - -
-------- ------------- ---------- ------------
Balance as of December 31, 2001 58,409 73,144 21,471 36,104
Goodwill amortization - - - -
Impairment losses - (73,144) - -
-------- ------------- ---------- ------------
Balance as of December 31, 2002 $ 58,409 $ - $ 21,471 $ 36,104
======== ============= ========== ============
47
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 3 - Goodwill (continued)
The following is a summary of pro forma net income (loss) and earnings
(loss) per share as adjusted to remove the amortization of goodwill (dollars in
thousands, except per share amounts):
Year Ended December 31,
--------------------------
2001 2000 (2)
---------- ----------
Net income (loss) - as reported $ 11,059 $ (19,045)
Goodwill amortization 7,482 7,482
Income tax impact (1) (1,131) (1,131)
---------- ----------
Net income (loss) - as adjusted $ 17,410 $ (12,694)
========== ==========
Basic earnings (loss) per share:
Net income (loss) - as reported $ 0.12 $ (0.23)
Goodwill amortization 0.08 0.09
Income tax impact (1) (0.01) (0.02)
---------- ----------
Net income (loss) - as adjusted $ 0.19 $ (0.16)
========== ==========
Diluted earnings (loss) per share:
Net income (loss) - as reported $ 0.12 $ (0.23)
Goodwill amortization 0.08 0.09
Income tax impact (1) (0.01) (0.02)
---------- ----------
Net income (loss) - as adjusted $ 0.19 $ (0.16)
========== ==========
(1) Certain goodwill amounts are non-deductible for tax purposes;
therefore, the income tax impact reflects only the deductible goodwill
amortization.
(2) Loss before extraordinary gain - as reported - $(22,981)
Loss before extraordinary gain - as adjusted - $(16,630)
48
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt
December 31,
---------------------
2002 2001
-------- --------
(Dollars in Thousands)
Senior Notes payable in November 2006 with interest of 9.75%
payable semi-annually in May and November, net of
unamortized premium of $790 and $2,085 at December 31,
2002 and 2001, respectively
(effective interest rate of 9.62%) $214,982 $452,065
Market adjustment for interest rate swap agreements, net of
amortization of $257 2,363 -
Senior Notes payable in November 2009 with interest of
10.125% payable semi-annually in May and November, net
of unamortized premium of $922 at December 31, 2002
(effective interest rate of 10.03%) 236,534 -
Convertible Subordinated Notes payable in August 2004 with
interest of 5.5% payable semi-annually in
February and August 124,509 124,509
Secured promissory note to Boeing Capital Corporation with
interest at 10.1278%, principal and interest
payable monthly over a 60-month term 10,588 15,589
Capital Lease and Other 954 9
-------- --------
Total debt 589,930 592,172
Less current portion 6,486 5,007
-------- --------
Total long-term debt $583,444 $587,165
======== ========
49
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt (continued)
The aggregate maturities of long-term debt for the five years ending
December 31, 2007 are as follows (000's): 2003 - $6,486; 2004 - $129,565; 2005 -
$0; 2006 - $214,192; 2007 - $0.
The Senior Notes were initially issued in November 1996 and in March 1998
in amounts of $300 million (Series B) and $150 million (Series C) at 9.75%. The
$300 million issue was sold at a $2.4 million discount while the $150 million
issue was sold at a premium of $5.7 million. In May 1998, a registration
statement was filed by the Company which offered to exchange the Series B and C
Notes for new Series D Notes. The form and terms of the Series D Notes are
identical in all material respects to the form and terms of the Series B and C
Notes, except for certain transfer restrictions and registration rights relating
to the Series C Notes. All of the Series B Notes except $189 thousand and all of
the Series C Notes were exchanged for new Series D Notes per this offering. As
discussed in Note 6, the Company entered into various interest rate swap
agreements to modify the interest characteristics of the Senior Notes.
On May 2, 2002, the Company announced it had successfully completed the
exchange of $235.6 million in principal amount of new 10.125% Senior Notes due
2009 ("New Notes") for a like amount of its 9.75% Senior Notes due 2006
("Outstanding Notes"), pursuant to an exchange offer described in the Offering
Circular dated April 1, 2002 (the "Exchange Offer"). The consummation of the
Exchange Offer was effected without registration, in reliance on the
registration exemption provided by Section 4(2) of the Securities Act of 1933,
as amended, which applies to offers and sales of securities that do not involve
a public offering, and Regulation D promulgated under that act. On July 1, 2002,
the Company filed a registration statement on Form S-4 offering to exchange the
New Notes for notes of the Company having substantially identical terms in all
material respects as the Outstanding Notes (the "Exchange Notes"). The offer to
exchange the New Notes for Exchange Notes was consummated on September 17, 2002.
The New Notes and Exchange Notes will be governed by the terms of the indenture
executed by the Company, the Subsidiary Guarantors and the trustee dated May 2,
2002, the terms of which are substantially the same as the terms of the 1998
Indenture, as amended by the Fourth Supplemental Indenture, as described below.
In connection with the Exchange Offer, the Company solicited consents to
certain amendments to the definitions and covenants in the indenture under which
the Outstanding Notes were issued, which all participants in the Exchange Offer
were deemed to have accepted. As a result of the participation in the Exchange
Offer of more than 50 percent of the holders of the Outstanding Notes, the
amendments to the 1998 Indenture were agreed, and which amendments have been
effected by the execution of the Fourth Supplemental Indenture by the Company,
the Subsidiary Guarantors and the trustee (as amended, the "1998 Indenture"). As
a result of the Exchange Offer, the Company incurred and expensed fees of
approximately $4.0 million.
50
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt (continued)
In July 1997, the Company issued $175 million of Convertible Subordinated
Notes due 2004. The Notes bear interest at 5.5% payable semi-annually in
February and August. The Notes are convertible at the option of the holder into
shares of common stock of Parker Drilling at $15.39 per share at any time prior
to maturity. The Notes are currently redeemable at the option of the Company at
certain stipulated prices. During the fourth quarter of 2000, the Company
repurchased on the open market $50.5 million principal amount of the 5.5% Notes
at an average price of 86.11 percent of face value, recognizing an extraordinary
gain of $3.9 million, net of $2.2 million of tax. The Note repurchases were
funded with proceeds from an equity offering in September 2000, whereby the
Company sold 13.8 million shares of common stock for net proceeds of
approximately $87.3 million. The amount of outstanding Notes at December 31,
2002 was $124.5 million.
On October 22, 1999, the Company entered into a $50.0 million revolving
loan facility with a group of banks led by Bank of America. The facility is
available for working capital requirements, general corporate purposes and to
support letters of credit and bears interest at prime plus 0.50% or LIBOR plus
2.50%. At December 31, 2002, no amounts have been drawn down against the
facility but $15.7 million of availability of $41.2 million (borrowing base at
December 31, 2002) has been used to support letters of credit that have been
issued. The revolver is collateralized by accounts receivable, inventory and
certain barge rigs located in the Gulf of Mexico. The facility will terminate on
October 22, 2003. The Company plans to renew or replace the revolving loan
facility by the end of the third quarter of 2003.
On October 7, 1999, a wholly owned subsidiary of the Company entered into a
loan agreement with Boeing Capital Corporation for the refinancing of a portion
of the capital cost of barge Rig 75. The loan principal of approximately $24.8
million plus interest is being repaid in 60 monthly payments of approximately
$0.5 million. The loan is collateralized by barge Rig 75 and is guaranteed by
Parker Drilling. The amount of principal outstanding at the end of 2002 was
$10.6 million.
Each of the 10.125% and the 9.75% Senior Notes, 5.5% Convertible
Subordinated Notes and the revolving loan facility contains customary
affirmative and negative covenants, including restrictions on incurrence of debt
and sales of assets. The revolving loan facility contains covenants which
require minimum adjusted tangible net worth, fixed charge coverage ratio and
limits annual capital expenditures. The revolving loan facility prohibits
payment of dividends and the indenture for the Senior Notes restricts the
payment of dividends.
51
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 5 - Guarantor/Non-Guarantor Consolidating Condensed Financial Statements
Set forth on the following pages are the consolidating condensed financial
statements of the restricted subsidiaries and our subsidiaries which are not
restricted by the Senior Notes. All of the Company's Senior Notes are guaranteed
by substantially all wholly owned subsidiaries of Parker Drilling. There are
currently no restrictions on the ability of the subsidiaries to transfer funds
to Parker Drilling in the form of cash dividends, loans or advances. Parker
Drilling is a holding company with no operations, other than through its
subsidiaries. In prior years, the non-guarantors were inconsequential,
individually and in the aggregate, to the consolidated financial statements and
separate financial statements of the guarantors were not presented because
management had determined that they would not be material to investors.
In August, 2002, Parker Drilling Company International Limited ("PDCIL")
entered into an agreement to sell two of its rigs in Kazakhstan to AralParker, a
Kazakhstan joint venture company owned 50 percent by PDCIL and 50 percent by a
Kazakhstan company. Because PDCIL has significant influence over the business
affairs of AralParker, its financial statements are consolidated with those of
the Company.
AralParker, Casuarina Limited (a wholly owned captive insurance company)
and Parker Drilling Investment Company are all non-guarantor subsidiaries whose
aggregate financial position and results of operations are no longer deemed to
be inconsequential and, accordingly the Company is providing consolidating
condensed financial information of the parent, Parker Drilling, the guarantor
subsidiaries, and the non-guarantor subsidiaries for the year ended December 31,
2002.
52
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
Year Ended December 31, 2002
--------------------------------------------------------------------------
Parent Guarantor Non-Guarantor Eliminations Consolidated
--------- --------- ------------- ------------ ------------
Drilling and rental revenues $ - $ 359,744 $ 27,772 $ 2,430 $ 389,946
Drilling and rental operating expenses 3 226,360 23,477 2,430 252,270
Depreciation and amortization 1 95,325 3,299 (122) 98,503
--------- --------- ------------ ------------ ------------
Drilling and rental operating income (loss) (4) 38,059 996 122 39,173
--------- --------- ------------ ------------ ------------
Construction contract revenue - 86,818 - - 86,818
Construction contract expense - 84,356 - - 84,356
--------- --------- ------------ ------------ ------------
Net construction contract operating income - 2,462 - - 2,462
--------- --------- ------------ ------------ ------------
General and administrative expense (1) 361 24,467 - (100) 24,728
Provision for reduction in carrying
value of certain assets - 1,500 - - 1,500
--------- --------- ------------ ------------ ------------
Total operating income (loss) (365) 14,554 996 222 15,407
--------- --------- ------------ ------------ ------------
Other income and (expense):
Interest expense (56,602) (43,106) (1,551) 48,850 (52,409)
Interest income 44,264 3,760 1,677 (48,850) 851
Other income (expense) - net (4,491) 8,374 109 (4,451) (459)
Equity in net earnings of subsidiaries (113,980) - - 113,980 -
--------- --------- ------------ ------------ ------------
Total other income and (expense) (130,809) (30,972) 235 109,529 (52,017)
--------- --------- ------------ ------------ ------------
Income (loss) before income taxes and cumulative
effect of change in accounting principle (131,174) (16,418) 1,231 109,751 (36,610)
Income tax expense (benefit): (17,120) 21,420 - - 4,300
--------- --------- ------------ ------------ ------------
Income (loss) before cumulative effect of change
in accounting principle (114,054) (37,838) 1,231 109,751 (40,910)
Cumulative effect of change in accounting principle - (73,144) - - (73,144)
--------- --------- ------------ ------------ ------------
Net income (loss) $(114,054) $(110,982) $ 1,231 $ 109,751 $ (114,054)
========= ========= ============ ============ ============
(1) All field operations general and administrative expenses are included in
operating expenses.
53
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)
December 31, 2002
------------------------------------------------------------------------
Parent Guarantor Non-Guarantor Eliminations Consolidated
----------- ----------- ------------- ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents $ 43,254 $ 6,218 $ 2,510 $ - $ 51,982
Accounts and notes receivable, net 81,551 100,400 19,080 (111,668) 89,363
Rig materials and supplies - 17,161 - - 17,161
Other current assets - 8,567 27 37 8,631
----------- ----------- ----------- ----------- -----------
Total current assets 124,805 132,346 21,617 (111,631) 167,137
----------- ----------- ----------- ----------- -----------
Property, plant and equipment, net 151 614,088 40,633 (13,594) 641,278
Goodwill, net - 115,983 - - 115,983
Investment in subsidiaries and intercompany advances 808,784 531,959 21,521 (1,362,264) -
Other noncurrent assets 12,556 16,336 (103) 138 28,927
----------- ----------- ----------- ----------- -----------
Total assets $ 946,296 $ 1,410,712 $ 83,668 $(1,487,351) $ 953,325
=========== =========== =========== =========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt $ 5,532 $ 954 $ - $ - $ 6,486
Accounts payable and accrued liabilities 25,106 150,455 7,218 (132,037) 50,742
Accrued income taxes 1,069 3,278 - - 4,347
----------- ----------- ----------- ----------- -----------
Total current liabilities 31,707 154,687 7,218 (132,037) 61,575
----------- ----------- ----------- ----------- -----------
Long-term debt 583,444 - - - 583,444
Deferred income tax (45,473) 45,473 - - -
Other long-term liabilities 1,409 6,271 - - 7,680
Intercompany payables 74,583 490,099 44,557 (609,239) -
Stockholders' equity:
Common stock 15,465 61,748 121 (61,869) 15,465
Capital in excess of par value 434,998 1,024,953 5,330 (1,030,283) 434,998
Accumulated other comprehensive income 664 - - - 664
Accumulated deficit (150,501) (372,519) 26,442 346,077 (150,501)
----------- ----------- ----------- ----------- -----------
Total stockholders' equity 300,626 714,182 31,893 (746,075) 300,626
----------- ----------- ----------- ----------- -----------
Total liabilities and stockholders'
equity $ 946,296 $ 1,410,712 $ 83,668 $(1,487,351) $ 953,325
=========== =========== =========== =========== ===========
54
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
Year Ended December 31, 2002
------------------------------------------------------------------
Parent Guarantor Non-Guarantor Eliminations Consolidated
----------- ---------- ------------- ------------ --------------
Cash flows from operating activities:
Net income (loss) $(114,054) $(110,982) $ 1,231 $ 109,751 $(114,054)
Adjustments to reconcile net income (loss)
to net cash provided by (used) in operating activities:
Depreciation and amortization 1 95,325 3,299 (122) 98,503
Gain on disposition of assets (15) (8,049) 3 4,629 (3,432)
Cumulative effect of change in accounting
principle - 73,144 - - 73,144
Provision for reduction in carrying value of
certain assets - 1,500 - - 1,500
Deferred income taxes (17,120) - - - (17,120)
Expenses not requiring cash 6,874 4,060 - (4,889) 6,045
Equity in net earnings of subsidiaries 113,980 - - (113,980) -
Change in operating assets and liabilities 28,477 (25,608) (5,853) (8,421) (11,405)
--------- --------- --------- --------- ---------
Net cash provided by (used) in operating activities 18,143 29,390 (1,320) (13,032) 33,181
--------- --------- --------- --------- ---------
Cash flows from investing activities:
Proceeds from the sale of assets 144 6,307 - - 6,451
Capital expenditures (net of reimbursements) (81) (45,181) (43,932) 44,013 (45,181)
--------- --------- --------- --------- ---------
Net cash provided by (used) in investing activities 63 (38,874) (43,932) 44,013 (38,730)
--------- --------- --------- --------- ---------
Cash flows from financing activities:
Principal payments under debt obligations (5,489) - - - (5,489)
Proceeds from interest rate swap agreements 2,620 - - - 2,620
Intercompany advances, net (23,020) 7,630 46,371 (30,981) -
--------- --------- --------- --------- ---------
Net cash provided by (used) in financing activities (25,889) 7,630 46,371 (30,981) (2,869)
--------- --------- --------- --------- ---------
Net change in cash and cash equivalents (7,683) (1,854) 1,119 - (8,418)
Cash and cash equivalents at beginning of year 50,937 8,072 1,391 - 60,400
--------- --------- --------- --------- ---------
Cash and cash equivalents at end of year $ 43,254 $ 6,218 $ 2,510 $ - $ 51,982
========= ========= ========= ========= =========
55
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 6 - Derivative Financial Instruments
The Company is exposed to interest rate risk from its fixed-rate debt. The
Company has hedged against a portion of the risk of changes in fair value
associated with its $214.2 million 9.75% Senior Notes by entering into three
fixed-to-variable interest rate swap agreements with a total notional amount of
$150.0 million. The terms of the interest rate swap agreements are as follows:
Months Notional Amount Fixed Rate Floating Rate
- ----------------------------- --------------- ---------- -------------------------
(Dollars in Thousands)
December 2001 - November 2006 $ 50,000 9.75% Three-month LIBOR
plus 446 basis points
January 2002 - November 2006 $ 50,000 9.75% Three-month LIBOR
plus 475 basis points
January 2002 - November 2006 $ 50,000 9.75% Three-month LIBOR
plus 482 basis points
The Company assumes no ineffectiveness as each interest rate swap agreement
meets the short-cut method requirements under SFAS No. 133 for fair value hedges
of debt instruments. As a result, changes in the fair value of the interest rate
swap agreements are offset by changes in the fair value of the debt and no net
gain or loss is recognized in earnings. During the year ended December 31, 2002,
the interest rate swap agreements reduced interest expense by $2.9 million.
On July 24, 2002, the Company terminated all the interest rate swap
agreements and received $3.5 million. A gain totaling $2.6 million will be
recognized as a reduction to interest expense over the remaining term (ending
November 2006) of the debt instrument, of which $0.3 million was recognized
during 2002.
56
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes
Income (loss) before income taxes, cumulative effect of change in
accounting principle and extraordinary gain is summarized as follows (dollars in
thousands):
Year Ended December 31,
----------------------------------------------------------------------
2002 2001 2000
------------ ------------ -----------
United States $(54,068) $ 8,751 $(29,253)
Foreign 17,458 14,896 10,595
-------- -------- --------
$(36,610) $ 23,647 $(18,658)
======== ======== ========
Income tax expense (benefit) is summarized as follows (dollars in thousands):
Year Ended December 31,
----------------------------------------------------------------------
2002 2001 2000
------------ ------------ -----------
Current:
United States:
Federal $ 104 $ 530 $ -
State - - -
Foreign 21,316 13,957 15,625
Deferred:
United States:
Federal (17,120) (1,846) (10,988)
State - (53) (314)
-------- -------- --------
$ 4,300 $ 12,588 $ 4,323
======== ======== ========
57
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes (continued)
Total income tax expense (benefit) differs from the amount computed by
multiplying income (loss) before income taxes by the U.S. federal income tax
statutory rate. The reasons for this difference are as follows (dollars in
thousands):
Year Ended December 31,
--------------------------------------------------------------------------------------------------------
2002 2001 2000
-------------------------------- ------------------------------------ --------------------------------
% of % of % of
Pre-Tax Pre-Tax Pre-Tax
Amount Income Amount Income Amount Income
---------------- --------------- ------------------ ---------------- --------------- ---------------
Computed expected tax
expense (benefit) $(12,814) (35%) $ 8,276 35% $ (6,530) (35%)
Foreign taxes, net of
federal benefit 13,855 38% 9,072 38% 10,156 54%
Change in valuation
allowance (2,927) (8%) (9,593) (41%) (6,097) (33%)
Foreign corporation
losses 3,234 9% 3,689 16% 4,253 23%
Goodwill amortization 2,781 8% 1,488 6% 1,488 8%
Other 171 - (344) (1%) 1,053 6%
-------- -------- -------- -------- -------- --------
Actual tax expense $ 4,300 12% $ 12,588 53% $ 4,323 23%
======== ======== ======== ======== ======== ========
58
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes (continued)
The components of the Company's tax assets and (liabilities) as of December
31, 2002 and 2001 are shown below (dollars in thousands):
December 31,
--------------------------------------------
2002 2001
------------------ --------------
Deferred tax assets:
Net operating loss carryforwards $ 49,529 $ 56,025
Alternative minimum tax carryforwards 401 983
Reserves established against realization of certain assets 2,937 1,874
Accruals not currently deductible for tax purposes 5,814 6,388
-------- --------
58,681 65,270
Deferred tax liabilities:
Property, plant and equipment (43,337) (65,079)
Goodwill (8,335) (6,180)
Unrealized gain on investments held for sale - (227)
-------- --------
Net deferred tax (liability) asset 7,009 (6,216)
Valuation allowance (7,009) (9,936)
-------- --------
Deferred income tax liability $ - $(16,152)
======== ========
The change in the valuation allowance in 2002 is the result of higher
utilization of net operating loss carryforwards previously reserved because they
were expected to expire unused. The Company has a remaining valuation allowance
of $7,009,000 with respect to its net deferred tax asset for the amount of net
operating loss carryforwards expected to expire unused. However, the amount of
the asset considered realizable could be different in the near term if estimates
of future taxable income change.
At December 31, 2002, the Company had $141,510,000 of net operating loss
carryforwards. For tax purposes the net operating loss carryforwards expire over
a 20-year period ending December 31 as follows: 2007 - $10,141,000; 2008 -
$11,968,000; 2009 - $6,700,000; thereafter - $112,701,000.
59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity
In September 2000, the Company sold 13.8 million common shares in a public
offering, resulting in net proceeds (after deducting issuance costs) of $87.3
million. The proceeds were used to acquire, upgrade and refurbish certain
offshore and land drilling rigs and for general corporate purposes, including
the repayment of debt.
Stock Plans
The Company's employee and non-employee director stock plans are summarized
as follows:
The 1994 Non-Employee Director Stock Option Plan ("Director Plan") provides
for the issuance of options to purchase up to 200,000 shares of Parker
Drilling's common stock. The option price per share is equal to the fair market
value of a Parker Drilling share on the date of grant. The term of each option
is 10 years, and an option first becomes exercisable six months after the date
of grant. All shares available for issuance under this plan have been granted.
The 1994 Executive Stock Option Plan provides that the directors may grant
a maximum of 2,400,000 shares to key employees of the Company and its
subsidiaries through the granting of stock options, stock appreciation rights
and restricted and deferred stock awards. The option price per share may not be
less than 50 percent of the fair market value of a share on the date the option
is granted, and the maximum term of a non-qualified option may not exceed 15
years and the maximum term of an incentive option is 10 years. All shares
available for issuance under this plan have been granted.
The 1997 Stock Plan initially authorized 4,000,000 shares to be available
for granting to officers and key employees who, in the opinion of the board of
directors, were in a position to contribute to the growth, management and
success of the Company. This plan was approved by the board of directors as a
"broad-based" plan under the interim rules of the New York Stock Exchange and,
as a result, more than 50 percent of the awards under this plan have been made
to non-executive employees. The option price per share may not be less than the
fair market value on the date the option is granted for incentive options and
not less than par value of a share of common stock for non-qualified options.
The maximum term of an incentive option is 10 years and the maximum term of a
non-qualified option is 15 years. The plan was amended in July 1999, April 2001
and September 2002, to grant authority to the compensation committee to issue
awards and to authorize 2,000,000; 1,000,000; and 1,800,000 additional shares,
respectively, for issuance, which shares were registered with the SEC. As of
December 31, 2002, there were 1,227,700 shares available for granting.
60
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
Information regarding the Company's stock option plans is summarized below:
1994 Director Plan
-----------------------------------------------
Weighted
Average
Exercise
Shares Price
---------------------- --------------------
Shares under option:
Outstanding at December 31, 1999 200,000 $ 8.431
Granted - -
Exercised - -
Cancelled - -
---------------------- --------------------
Outstanding at December 31, 2000 200,000 8.431
Granted - -
Exercised - -
Cancelled - -
---------------------- --------------------
Outstanding at December 31, 2001 200,000 8.431
Granted - -
Exercised - -
Cancelled - -
---------------------- --------------------
Outstanding at December 31, 2002 200,000 $ 8.431
====================== ====================
61
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
1994 Option Plan
---------------------------------------------------------------------------------------
Incentive Options Non-Qualified Options
---------------------------------------- -------------------------------------------
Weighted Weighted
Average Average
Exercise Exercise
Shares Price Shares Price
---------------- -------------------- -------------------- -------------------
Shares under option:
Outstanding at December 31, 1999 622,564 $ 7.227 1,586,936 $ 6.975
Granted - - - -
Exercised - - (18,750) 2.250
Cancelled - - - -
---------------- -------------------- -------------------- -------------------
Outstanding at December 31, 2000 622,564 7.227 1,568,186 7.032
Granted - - - -
Exercised (17,000) 4.500 (1,250) 2.250
Cancelled - - - -
---------------- -------------------- -------------------- -------------------
Outstanding at December 31, 2001 605,564 7.303 1,566,936 7.036
Granted - - - -
Exercised - - - -
Cancelled - - - -
---------------- -------------------- -------------------- -------------------
Outstanding at December 31, 2002 605,564 $ 7.303 1,566,936 $ 7.036
================ ==================== ==================== ===================
62
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
1997 Stock Plan
--------------------------------------------------------------------------------------------
Incentive Options Non-Qualified Options
-------------------------------------------- --------------------------------------------
Weighted Weighted
Average Average
Exercise Exercise
Shares Price Shares Price
-------------------- -------------------- -------------------- --------------------
Shares under option:
Outstanding at December 31, 1999 2,794,125 $ 8.038 2,065,575 $ 6.523
Granted 50,000 5.938 15,000 5.062
Exercised (92,094) 3.188 (24,370) 3.188
Cancelled (30,130) 8.564 (2,870) 3.188
-------------------- -------------------- -------------------- --------------------
Outstanding at December 31, 2000 2,721,901 8.158 2,053,335 6.556
Granted - - 1,485,000 5.167
Exercised (137,061) 3.193 (31,915) 3.188
Cancelled - - - -
-------------------- -------------------- -------------------- --------------------
Outstanding at December 31, 2001 2,584,840 8.421 3,506,420 6.000
Granted - - 1,385,000 2.301
Exercised (10,196) 3.188 (8,053) 3.188
Cancelled (84,884) 9.020 (105,817) 6.391
-------------------- -------------------- -------------------- --------------------
Outstanding at December 31, 2002 2,489,760 $ 8.422 4,777,550 $ 4.924
==================== ==================== ==================== ====================
63
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
Outstanding Options
------------------------------------
Weighted
Average Weighted
Remaining Average
Number of Contractual Exercise
Plan Exercise Prices Shares Life Price
- ------------------------------------------------------------- ---------------- -------------------- --------------
1994 Director Plan $ 3.281 - $ 6.125 40,000 4.4 years $ 4.827
$ 8.875 - $ 12.094 160,000 5.5 years $ 9.332
1994 Executive Option Plan
Incentive option $ 4.500 217,554 3.0 years $ 4.500
Incentive option $ 8.875 388,010 5.4 years $ 8.875
Non-qualified $ 2.250 434,946 3.0 years $ 2.250
Non-qualified $ 8.875 1,131,990 5.4 years $ 8.875
1997 Stock Plan
Incentive option $ 3.188 - $ 5.938 791,430 3.4 years $ 3.362
Incentive option $ 8.875 - $ 12.188 1,698,330 4.2 years $ 10.780
Non-qualified $ 2.240 - $ 6.070 3,653,380 5.2 years $ 3.651
Non-qualified $ 8.875 - $ 10.813 1,124,170 4.6 years $ 9.060
Exercisable Options
--------------------------------------
Weighted
Average
Number of Exercise
Plan Exercise Prices Shares Price
- ----------------------------------------------------------------------- --------------- --------------
1994 Director Plan $ 3.281 - $ 6.125 40,000 $ 4.827
$ 8.875 - $ 12.094 160,000 $ 9.332
1994 Executive Option Plan
Incentive option $ 4.500 217,554 $ 4.500
Incentive option $ 8.875 388,010 $ 8.875
Non-qualified $ 2.250 434,946 $ 2.250
Non-qualified $ 8.875 1,131,990 $ 8.875
1997 Stock Plan
Incentive option $ 3.188 - $ 5.938 778,930 $ 3.321
Incentive option $ 8.875 - $ 12.188 1,698,330 $ 10.780
Non-qualified $ 2.240 - $ 6.070 1,894,630 $ 3.820
Non-qualified $ 8.875 - $ 10.813 1,124,170 $ 9.060
64
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
The Company has three additional stock plans which provide for the issuance
of stock for no cash consideration to officers and key non-officer employees.
Under two of the plans, each employee receiving a grant of shares may dispose of
15 percent of the grant on each annual anniversary date from the date of grant
for the first four years and the remaining 40 percent on the fifth-year
anniversary. These two plans have a total of 11,375 shares reserved and
available for granting. Shares granted under the third plan are fully vested no
earlier than 24 months from the effective date of the grant and not later than
36 months. The third plan has a total of 1,562,195 shares reserved and available
for granting. No shares were granted under these plans in 2002, 2001 and 2000.
In prior years the Company purchased shares from certain of its employees,
who received stock through its stock option plan, at fair market value. At
December 31, 2001, 604,870 shares were held in Treasury which includes 98,293
shares purchased by the Company at the fair market value of $289,479. These
shares were issued to the Stock Bonus Plan as the Company's matching
contribution. The Plan was funded in January 2002. At December 31, 2002, 506,577
shares were held in Treasury.
65
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
Stock Reserved For Issuance
The following is a summary of common stock reserved for issuance:
December 31,
----------------------------------------
2002 2001
---------- ----------
Stock plans 12,441,135 10,659,380
Stock bonus plan 1,577,221 81,715
Convertible notes 8,090,254 8,090,254
---------- ----------
Total shares reserved for issuance 22,108,610 18,831,349
========== ==========
Stockholder Rights Plan
The Company adopted a stockholder rights plan on June 25, 1998, to assure
that the Company's stockholders receive fair and equal treatment in the event of
any proposed takeover of the Company and to guard against partial tender offers
and other abusive takeover tactics to gain control of the Company without paying
all stockholders a fair price. The rights plan was not adopted in response to
any specific takeover proposal. Under the rights plan, the Company's board of
directors declared a dividend of one right to purchase one one-thousandth of a
share of a new series of junior participating preferred stock for each
outstanding share of common stock. The plan was amended on September 22, 1998,
to eliminate the restriction on the board of directors' ability to redeem the
shares for two years in the event the majority of the board of directors does
not consist of the same directors that were in office as of June 25, 1998
("Continuing Directors"), or directors that were recommended to succeed
Continuing Directors by a majority of the Continuing Directors.
The rights may only be exercised 10 days following a public announcement
that a third party has acquired 15 percent or more of the outstanding common
shares of the Company or 10 days following the commencement of, or announcement
of an intention to make a tender offer or exchange offer, the consummation of
which would result in the beneficial ownership by a third party of 15 percent or
more of the common shares. When exercisable, each right will entitle the holder
to purchase one one-thousandth share of the new series of junior participating
preferred stock at an exercise price of $30, subject to adjustment. If a person
or group acquires 15 percent or more of the outstanding common shares of the
Company, each right, in the absence of timely redemption of the rights by the
Company, will entitle the holder, other than the acquiring party, to purchase
for $30, common shares of the Company having a market value of twice that
amount.
The rights, which do not have voting privileges, expire June 30, 2008, and
at the Company's option, may be redeemed by the Company in whole, but not in
part, prior to expiration for $0.01 per right. Until the rights become
exercisable, they have no dilutive effect on earnings per share.
66
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 9 - Reconciliation of Income and Number of Shares Used to Calculate Basic
and Diluted Earnings Per Share (EPS)
For the Year Ended December 31, 2002
---------------------------------------------------------------------------
Loss Shares Per-Share
(Numerator) (Denominator) Amount
-------------- --------------- --------------
Basic EPS:
Loss before cumulative effect of change
in accounting principle $ (40,910,000) 92,444,773 $ (0.44)
Cumulative effect of change in
accounting principle (73,144,000) 92,444,773 (0.79)
Net loss (114,054,000) 92,444,773 (1.23)
Effect of dilutive securities:
Stock options - - -
Diluted EPS:
Loss before cumulative effect of change
in accounting principle (40,910,000) 92,444,773 (0.44)
Cumulative effect of change in
accounting principle (73,144,000) 92,444,773 (0.79)
Net loss $(114,054,000) 92,444,773 $ (1.23)
============= ============= ========
For the Year Ended December 31, 2001
------------------------------------------------------------------------
Income Shares Per-Share
(Numerator) (Denominator) Amount
---------------- -------------- ---------------
Basic EPS:
Net income $11,059,000 92,008,877 $ 0.12
Effect of dilutive securities:
Stock options - 682,156 -
Diluted EPS:
Net income plus assumed conversions $11,059,000 92,691,033 $ 0.12
=========== =========== ========
67
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 9 - Reconciliation of Income and Number of Shares Used to Calculate Basic
and Diluted Earnings Per Share (EPS) (continued)
For the Year Ended December 31, 2000
--------------------------------------------------------------------------
Income (Loss) Shares Per-Share
(Numerator) (Denominator) Amount
---------------------- ----------------------- -----------------------
Basic EPS:
Loss before extraordinary gain $(22,981,000) 81,758,825 $ (0.28)
Extraordinary gain 3,936,000 81,758,825 0.05
Net loss (19,045,000) 81,758,825 (0.23)
Effect of dilutive securities:
Stock options - - -
Diluted EPS:
Loss before extraordinary gain (22,981,000) 81,758,825 (0.28)
Extraordinary gain 3,936,000 81,758,825 0.05
Net loss $(19,045,000) 81,758,825 $ (0.23)
============ ============ ========
The Company has outstanding $124,509,000 of 5.5% Convertible Subordinated
Notes, which are convertible into 8,090,254 shares of common stock at $15.39 per
share. The Notes have been outstanding since their issuance in July 1997, but
were not included in the computation of diluted EPS because the assumed
conversion of the Notes would have had an anti-dilutive effect on EPS. For the
year ended December 31, 2002, options to purchase 9,639,810 shares of common
stock at prices ranging from $2.24 to $12.1875, which were outstanding during
the period, were not included in the computation of diluted EPS because the
assumed exercise of the options would have had an anti-dilutive effect on EPS
due to the net loss incurred for 2002. For the fiscal year ended December 31,
2001, options to purchase 6,049,000 shares of common stock at prices ranging
from $5.00 to $12.1875, which were outstanding during the period, were not
included in the computation of diluted EPS because the options' exercise price
was greater than the average market price of the common shares during the
period. For the year ended December 31, 2000, options to purchase 7,166,036
shares of common stock, respectively, at prices ranging from $2.25 to $12.1875,
were outstanding but not included in the computation of diluted EPS because the
assumed exercise of the options would have had an anti-dilutive effect on EPS
due to the net loss during 2000.
68
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 10 - Employee Benefit Plans
The Parker Drilling Company Stock Bonus Plan ("Plan") was adopted effective
September 1980 for eligible employees of Parker Drilling and its subsidiaries
who have completed three months of service with the Company. It was amended in
1983 to qualify as a 401(k) plan under the Internal Revenue Code which permits a
specified percentage of an employee's salary to be voluntarily contributed on a
pre-tax basis and to provide for a Company matching feature. The Plan was
amended and restated generally effective January 1, 2001, to comply with certain
tax laws. The Plan was further amended effective January 1, 2002 to reflect
certain provisions of the Economic Growth and Tax Relief Reconciliation Act of
2001 ("EGTRRA"). Participants may contribute from one percent to 15 percent of
eligible earnings and direct contributions to one or more of 13 investment
funds. The Plan provides for dollar-for-dollar matching contributions by the
Company up to three percent of a participant's compensation and $0.50 for every
dollar contributed from three percent to five percent. The Company's matching
contribution is made in Parker Drilling common stock and vests immediately. Each
Plan year, additional Company contributions can be made, at the discretion of
the board of directors, in amounts not exceeding the permissible deductions
under the Internal Revenue Code. The Company issued 544,844; 343,289; and
361,855 shares to the Plan in 2002, 2001, and 2000 with the Company recognizing
expense of $1,472,437; $1,927,100; and $1,742,193 in each of the periods,
respectively.
69
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11 - Business Segments
The Company is organized into three primary business segments: U.S.
drilling operations, international drilling operations, and rental tools. This
is the basis management uses for making operating decisions and assessing
performance.
Year Ended December 31,
------------------------------------------------------------------
Operations by Industry Segment 2002 2001 2000
- --------------------------------------------------- ------------------- -------------------- -------------------
(Dollars in Thousands)
Drilling and rental revenues:
U.S. drilling $ 113,478 $ 190,809 $ 148,416
International drilling 228,958 231,527 185,100
Rental tools 47,510 65,629 42,833
------------------- -------------------- -------------------
Total drilling and rental revenues 389,946 487,965 376,349
------------------- -------------------- -------------------
Operating income (loss):
U.S. drilling (13,185) 33,138 6,766
International drilling 39,301 37,583 19,553
Rental tools 13,057 30,016 16,897
------------------- -------------------- -------------------
Total operating income by segment (1) 39,173 100,737 43,216
Net construction contract operating income 2,462 - -
General and administrative expense (24,728) (21,721) (20,392)
Provision for reduction in
carrying value of certain assets (1,500) - (8,300)
Reorganization expense - (7,500) -
------------------- -------------------- -------------------
Total operating income 15,407 71,516 14,524
Interest expense (52,409) (53,015) (57,036)
Minority interest 278
Other income, net 114 5,146 23,854
------------------- -------------------- -------------------
Income (loss) before income taxes $ (36,610) $ 23,647 $ (18,658)
=================== ==================== ===================
Identifiable assets:
U.S. drilling $ 307,811 $ 343,357 $ 356,090
International drilling 418,665 424,022 412,839
Rental tools 69,998 70,365 57,550
------------------- -------------------- -------------------
Total identifiable assets 796,474 837,744 826,479
Corporate assets 156,851 268,033 280,940
------------------- -------------------- -------------------
Total assets $ 953,325 $1,105,777 $1,107,419
=================== ==================== ===================
(1) Operating income by segment is calculated by excluding net
construction contract operating income, general and administrative
expense, provision for reduction in carrying value of certain assets
and reorganization expense from operating income, as reported in the
consolidated statement of operations.
70
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11 - Business Segments (continued)
Year Ended December 31,
-------------------------------------------------------------------
Operations by Industry Segment 2002 2001 2000
- ---------------------------------------------------- -------------------- ------------------- -------------------
(Dollars in Thousands)
Capital expenditures:
U.S. drilling $ 6,248 $ 41,366 $ 22,221
International drilling 22,452 53,732 55,215
Rental tools 14,864 24,210 16,168
Corporate 1,617 2,725 4,921
-------------------- ------------------- -------------------
Total capital expenditures $ 45,181 $ 122,033 $ 98,525
==================== =================== ===================
Depreciation and amortization:
U.S. drilling $ 40,164 $ 44,300 $ 42,458
International drilling 43,660 38,379 30,730
Rental tools 12,361 12,302 11,147
Corporate 2,318 2,278 725
-------------------- ------------------- -------------------
Total depreciation and amortization $ 98,503 $ 97,259 $ 85,060
==================== =================== ===================
71
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11- Business Segments (continued)
Year Ended December 31,
----------------------------------------------------------------
Operations by Geographic Area 2002 2001 2000
- ---------------------------------------------------- ------------------- ------------------ ------------------
(Dollars in Thousands)
Drilling and rental revenues:
United States $ 160,988 $ 256,438 $ 191,249
Latin America 40,444 54,063 58,467
Asia Pacific 38,294 32,246 15,373
Africa and Middle East 53,916 58,988 55,671
CIS 96,304 86,230 55,589
------------------- ------------------ ------------------
Total drilling and rental revenues 389,946 487,965 376,349
------------------- ------------------ ------------------
Operating income (loss):
United States (128) 63,154 23,663
Latin America (542) 2,385 6,554
Asia Pacific 14,127 11,304 (1,905)
Africa and Middle East 9,422 11,933 8,562
CIS 16,294 11,961 6,342
------------------- ------------------ ------------------
Total operating income by segment (1) 39,173 100,737 43,216
Net construction contract operating income 2,462 - -
General and administrative expense (24,728) (21,721) (20,392)
Provision for reduction in
carrying value of certain assets (1,500) - (8,300)
Reorganization expense - (7,500) -
------------------- ------------------ ------------------
Total operating income 15,407 71,516 14,524
Interest expense (52,409) (53,015) (57,036)
Minority interest 278 - -
Other income, net 114 5,146 23,854
------------------- ------------------ ------------------
Income (loss) before income taxes $ (36,610) $ 23,647 $ (18,658)
=================== ================== ==================
Identifiable assets:
United States $ 534,660 $ 681,756 $ 702,639
Latin America 88,985 93,722 93,896
Asia Pacific 46,385 39,963 41,602
Africa and Middle East 99,496 94,986 119,607
CIS 183,799 195,350 149,675
------------------- ------------------ ------------------
Total identifiable assets $ 953,325 $1,105,777 $1,107,419
=================== ================== ==================
(1) Operating income by segment is calculated by excluding net
construction contract operating income, general and administrative
expense, provision for reduction of carrying value of certain assets
and reorganization expense from operating income, as reported in the
consolidated statement of operations.
72
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies
At December 31, 2002, the Company had a $50.0 million revolving credit
facility available for general corporate purposes and to support letters of
credit. As of December 31, 2002, $15.7 million of availability has been reserved
to support letters of credit that have been issued. At December 31, 2002, no
amounts had been drawn under the revolving credit facility.
The Company has various lease agreements for office space, equipment,
vehicles and personal property. These obligations extend through 2009 and are
typically non-cancelable. Most leases contain renewal options and certain of the
leases contain escalation clauses. Future minimum lease payments at December 31,
2002, under operating leases with non-cancelable terms in excess of one year,
are as follows:
2003 $ 3,317
2004 2,264
2005 2,037
2006 2,328
2007 1,315
Thereafter 2,145
----------------
Total $13,406
================
Total rent expense for all operating leases amounted to $10.9 million for
2002, $5.5 million for 2001, and $3.7 million for 2000.
Each of the executive officers entered into an employment agreement with
the Company that became effective during 2002. The term of each agreement is
for three years and each provide for automatic extensions of two years, with
the exception of Mr. Brassfield and Mr. Wingerter, whose agreements are for two
years, and Mr. Robert L. Parker whose agreement is for one year. The employment
agreements provide for the following benefits:
*payment of current salary, which may be increased upon review by CEO (or
the Board of Directors in case of CEO and Chairman) on an annual basis
but cannot be reduced except with consent of the executive,
*for payment of target bonuses of up to 100 percent of salary based on
meeting certain incentives (75 percent for Mr. Nash and Mr. Whalen and
50 percent for Mr. Wingerter and Mr. Brassfield), and
*to be eligible to receive stock options and to participate in other
benefits, including without limitation, paid vacation, 401(k) plan,
health insurance and life insurance.
73
If the executive's employment is terminated, including by reason of death
or disability or retirement, but excluding termination for cause or termination
as a result of the resignation of the executive, unless for good reason (based
on definitions of cause and good reason in the agreements), the executive is
entitled to receive:
*salary for remainder of month of the termination,
*bonus for the prior year if earned and yet unpaid,
*remainder of vacation pay for the year,
*a severance payment equal to two times the sum of the highest salary and
bonus over the previous three years, except for Mr. Brassfield and
Mr. Wingerter whose payment will be based on a 1.5 times multiplier
("Additional Benefit"), and
*continued health benefits for two years, except for Mr. Brassfield and
Mr. Wingerter who will receive these benefits for 1.5 years ("Other
Benefits").
In consideration for these benefits the executive agrees to perform his
customary duties set forth in the employment agreement, and further covenants
not to solicit business except on behalf of the Company during his employment
and to refrain from hiring employees of the Company or to compete against the
Company for a period of one year following his termination.
In addition to the above benefits, each employment agreement provides that
in the event of a change in control, as defined in the agreement, the term of
the employment agreement will be extended for three years. If the executive is
terminated during this three year period for any reason except for cause or the
executive resigns during the first two years after the change in control for
good reason, the Additional Benefit payable shall be based on three times
salary and bonus, payable in a lump sum, and the Other Benefits shall also be
provided for three years. In certain circumstances, the Company has agreed to
make the executive whole for excise taxes that may apply with respect to
payments made after a change in control. The benefits provided under the
employment agreements executed by the executive officers are in lieu of and
replace the benefits under the Severance Compensation and Consulting Agreements
previously executed by the executive officers, which Severance Compensation and
Consulting Agreements have been terminated.
In addition to the executive officers, six other officers and key
employees entered into employment agreements that were effective on November 1,
2002, with three agreements with officers providing for similar severance
benefits, including change in control provisions, and the remaining agreements
providing similar benefits at lower levels without change in control provisions.
74
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies (continued)
The drilling of oil and gas wells is subject to various federal, state,
local and foreign laws, rules and regulations. The Company, as an owner or
operator of both onshore and offshore facilities operating in or near waters of
the United States, may be liable for the costs of removal and damages arising
out of a pollution incident to the extent set forth in the Federal Water
Pollution Control Act, as amended by the Oil Pollution Act of 1990 ("OPA") and
the Outer Continental Shelf Lands Act. In addition, the Company may also be
subject to applicable state law and other civil claims arising out of any such
incident. Certain of the Company's facilities are also subject to regulations of
the Environmental Protection Agency ("EPA") that require the preparation and
implementation of spill prevention, control and countermeasure plans relating to
possible discharge of oil into navigable waters. Other regulations of the EPA
may require certain precautions in storing, handling and transporting hazardous
wastes. State statutory provisions relating to oil and natural gas generally
include requirements as to well spacing, waste prevention, production
limitations, pollution prevention and cleanup, obtaining drilling and dredging
permits and similar matters.
On July 6, 2001, the Ministry of State Revenues of Kazakhstan ("MSR")
issued an Act of Audit to the Kazakhstan branch ("PKD Kazakhstan") of Parker
Drilling Company International Limited ("PDCIL"), a wholly owned subsidiary of
the Company, assessing additional taxes of approximately $29.0 million for the
years 1998-2000. The assessment consisted primarily of adjustments in corporate
income tax based on a determination by the Kazakhstan tax authorities that
payments by Offshore Kazakhstan International Operating Company, ("OKIOC"), to
PDCIL of $99.0 million, in reimbursement of costs for modifications to Rig 257,
performed by PDCIL prior to the importation of the drilling rig into Kazakhstan,
are income to PKD Kazakhstan, and therefore, taxable to PKD Kazakhstan. PKD
Kazakhstan filed an Act of Non-Agreement that such reimbursements should not be
taxable and requested that the Act of Audit be revised accordingly. In November
2001, the MSR rejected PKD Kazakhstan's Act of Non-Agreement, prompting PKD
Kazakhstan to seek judicial review of the assessment. On December 28, 2001, the
Astana City Court issued a judgment in favor of PKD Kazakhstan, finding that the
reimbursements to PDCIL were not income to PKD Kazakhstan and not otherwise
subject to tax based on the U.S.-Kazakhstan Tax Treaty. The MSR appealed the
decision of the Astana City Court to the Civil Panel of the Supreme Court, which
confirmed the decision of the Astana City Court that the reimbursements were not
income to PKD Kazakhstan in March 2002. Although the court agreed with the MSR's
position on certain minor issues, no additional taxes will be payable as a
result of this assessment. The MSR has until the end of March 2003 to appeal the
decision of the Civil Panel to the Supervisory Panel of the Supreme Court of
Kazakhstan. It may also reopen the case thereafter if material new evidence is
discovered. In addition, the Company has filed a petition with the U.S. Treasury
Department for competent authority review, which is a tax treaty procedure to
resolve disputes as to which country may tax income covered under the treaty.
The U.S. Treasury Department has granted our petition and has initiated
proceedings with the MSR which is ongoing.
The Company is a party to various other lawsuits and claims arising out of
the ordinary course of business. Management, after review and consultation with
legal counsel, considers that any liability resulting from these matters would
not materially affect the results of operations, the financial position or the
net cash flows of the Company.
75
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 13 - Related Party Transactions
On February 27, 1995, the Company entered into a Split Dollar Life
Insurance Agreement with Robert L. Parker and the Robert L. Parker and
Catherine M. Parker Family Trust under Indenture dated 23rd day of July 1993
("Trust") pursuant to which the Company agreed to provide life insurance
protection for Mr. and Mrs. Robert L. Parker in the event of the death of Mr.
and Mrs. Parker (the "Agreement"). The Agreement provided that the Trust would
acquire and own a life insurance policy with face amount of $13.2 million and
that the Company would pay the premiums subject to reimbursement by the Trust
out of the proceeds of the policy, with interest to accrue on the premium
payments made by the Company from and after January 1, 2000, at the one-year
Treasury bill rate. The repayment of the premiums was secured by an Assignment
of Life Insurance Policy as Collateral of same date as the Agreement. On
October 14, 1996, the Agreement was amended to provide that interest accrual
would be deferred until February 28, 2003, in consideration for the Company's
termination of a separate life insurance policy on the life of Robert L. Parker.
On April 19, 2000, the Agreement was amended and restated to replace the
previous policy with two policies, one for $8.0 million on the life of Robert L.
Parker and one for $7.7 million on the lives of both Mr. and Mrs. Robert L.
Parker. Mr. Robert L. Parker Jr., the Company's CEO and son of Robert L. Parker
will receive one third of the net proceeds of the policies.
As of December 31, 2002, the accrued amount of premiums paid by the
Company on the policies and to be reimbursed by the Trust to the Company was
$4.7 million. Due to the adoption of the Sarbanes-Oxley Act of 2002 ("SOX"),
additional loans to executive officers and directors may be prohibited,
although continuance of loans in existence as of July 30, 2002, are allowed;
provided there is no modification to such loans. Because the advancement of
additional annual premiums by the Company may be considered a prohibited loan
under SOX, the Company elected to not advance the $0.6 million premium that was
due in December 2002 pending further clarification from the SEC as to how the
Company's obligation to advance these premiums under the Agreement can be
honored without violating SOX.
Note 14 - Supplementary Information
At December 31, 2002, accrued liabilities included $8.5 million of accrued
interest expense, $4.4 million of workers' compensation and health plan
liabilities and $7.0 million of accrued payroll and payroll taxes. At December
31, 2001, accrued liabilities included $8.2 million of accrued interest expense,
$5.3 million of workers' compensation and health plan liabilities and $10.4
million of accrued payroll and payroll taxes. Other long-term obligations
included $4.7 million and $3.8 million of workers' compensation liabilities as
of December 31, 2002 and 2001, respectively.
76
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 15 - Selected Quarterly Financial Data (Unaudited)
Quarter
------------------------------------------------------------------------------------
Year 2002 First Second Third Fourth Total
- ----------------------------------- ---------- --------- --------- --------- -----------
(Dollars in Thousands Except Per Share Amounts)
Revenues $ 96,225 $ 97,814 $ 100,079 $ 95,828 $ 389,946
Gross profit (1) $ 8,468 $ 6,600 $ 12,587 $ 11,518 $ 39,173
Operating income $ 2,809 $ 1,027 $ 5,760 $ 5,811 $ 15,407
Net income (loss) before
cumulative effect of
change in accounting
principle $ (11,069) $ (11,489) $ (8,020) $ (10,332) $ (40,910)
Cumulative effect of
change in accounting
principle (3) $ (73,144) $ - $ - $ - $ (73,144)
Net income (loss) $ (84,213) $ (11,489) $ (8,020) $ (10,332) $ (114,054)
Basic earnings (loss) per
share (2):
Loss before cumulative
effect of change in
accounting principle $ (0.12) $ (0.12) $ (0.09) $ (0.11) $ (0.44)
Cumulative effect of
change in accounting
principle $ (0.79) $ - $ - $ - $ (0.79)
Net income (loss) $ (0.12) $ (0.91) $ (0.09) $ (0.11) $ (1.23)
Diluted earnings (loss) per
share (2):
Loss before cumulative
effect of change in
accounting principle $ (0.12) $ (0.12) $ (0.09) $ (0.11) $ (0.44)
Cumulative effect of
change in accounting
principle $ (0.79) $ - $ - $ - $ (0.79)
Net income (loss) $ (0.12) $ (0.91) $ (0.09) $ (0.11) $ (1.23)
(1) Gross profit is calculated by excluding net construction contract,
operating income, general and administrative expense, reorganization
expense and provision for reduction in carrying value of certain
assets from operating income, as reported in the consolidated
statement of operations.
(2) As a result of shares issued during the year, earnings per share for
the year's four quarters, which are based on weighted average shares
outstanding during each quarter, do not equal the annual earnings per
share, which is based on the weighted average shares outstanding
during the year.
(3) The first quarter includes recognition of $73.1 million goodwill
impairment related to the jackup and platform rigs resulting from the
adoption of SFAS No. 142. The impairment provision was included in
the second quarter Form 10-Q, retroactive to January 1, 2002.
77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 15 - Selected Quarterly Financial Data (continued) (Unaudited)
Quarter
---------------------------------------------------------------------------
Year 2001 First Second Third Fourth Total
- ------------------------------------------- ----------- ----------- ----------- ----------- -----------
(Dollars in Thousands Except Per Share Amounts)
Revenues $ 114,874 $ 132,915 $ 128,927 $ 111,249 $ 487,965
Gross profit (1) $ 22,480 $ 33,333 $ 29,606 $ 15,318 $ 100,737
Operating income $ 17,609 $ 23,130 $ 22,375 $ 8,402 $ 71,516
Net income (3) $ 1,524 $ 2,692 $ 3,025 $ 3,818 $ 11,059
Basic earnings per share: (2)
Net income $ 0.02 $ 0.03 $ 0.03 $ 0.04 $ 0.12
Diluted earnings per share: (2)
Net income $ 0.02 $ 0.03 $ 0.03 $ 0.04 $ 0.12
(1) Gross profit is calculated by excluding general and administrative
expense, reorganization expense and provision for reduction in
carrying value of certain assets from operating income, as reported in
the Consolidated Statement of Operations.
(2) As a result of shares issued during the year, earnings per share for
the year's four quarters, which are based on weighted average shares
outstanding during each quarter, do not equal the annual earnings per
share, which is based on the weighted average shares outstanding
during the year.
(3) The fourth quarter includes a $9.6 million deferred tax benefit
resulting from a reversal of a valuation allowance. See Note 7.
78
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 16 - Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standard Board ("FASB") issued SFAS
No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002 and establishes an
accounting standard requiring the recording of the fair value of liabilities
associated with the retirement of long-term assets in the period in which the
liability is incurred. Accordingly, we adopted this standard in the first
quarter of 2003. We do not expect this standard to have a material impact on our
financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 was effective January
1, 2002. This statement supersedes SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and amends
Accounting Principles Board Opinion ("APB") No. 30 for the accounting and
reporting of discontinued operations, as it relates to long-lived assets. Our
adoption of SFAS No. 144 did not affect our financial position or results of
operations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 is effective for fiscal years beginning after May 15,
2002. We will adopt this standard in 2003 and do not expect it to have a
significant effect on our results of operations or our financial position.
In July 2002, the FASB issued SFAS No. 146, "Accounting For Costs
Associated with Exit or Disposal Activities." SFAS No. 146 is effective for exit
or disposal activities initiated after December 31, 2002. We do not expect the
adoption of this standard to have any impact on our financial position or
results of operations.
On December 31, 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure-An Amendment of SFAS No.
123." The standard provides additional transition guidance for companies that
elect to voluntarily adopt the accounting provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." SFAS No. 148 does not change the
provisions of SFAS No. 123 that permit entities to continue to apply the
intrinsic value method of APB No. 25, "Accounting for Stock Issued to
Employees." As we continue to follow APB No. 25, our accounting for stock-based
compensation will not change as a result of SFAS No. 148. SFAS No. 148 does
require certain new disclosures in both annual and interim financial statements.
The required annual disclosures are effective immediately and have been included
in Note 1 of the notes to the consolidated financial statements. The new interim
disclosure provisions will be effective in the first quarter of 2003.
79
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 16 - Recent Accounting Pronouncements (continued)
In November 2002, the FASB issued FASB Interpretation ("FIN") 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantee of Indebtedness of Others." FIN 45 requires that upon
issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee. FIN 45's provisions for
initial recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The guarantor's previous
accounting for guarantees that were issued before the date of FIN 45's initial
application may not be revised or restated to reflect the effect of the
recognition and measurement provisions of the interpretation. The disclosure
requirements are effective for financial statements of both interim and annual
periods that end after December 15, 2002. The Company is not a guarantor under
any significant guarantees and thus this interpretation is not expected to have
a significant effect on the Company's financial position or results of
operations.
On January 17, 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities, An Interpretation of Accounting Research Bulletin No. 51."
The primary objectives of FIN 46 are to provide guidance on how to identify
entities for which control is achieved through means other than through voting
rights (variable interest entities or ("VIE")) and how to determine when and
which business enterprise should consolidate the VIE. This new model for
consolidation applies to an entity in which either (1) the equity investors do
not have a controlling financial interest or (2) the equity investment at risk
is insufficient to finance that entity's activities without receiving additional
subordinated financial support from other parties. See Note 1 of the notes to
the consolidated financial statements regarding our consolidation of AralParker,
a company in which we own a 50 percent equity interest. We are consolidating
this company because we exert significant influence and have a financial
interest in the form of a loan, in addition to our equity interest.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
This item is not applicable to the Company in that disclosure is required
under Regulation S-X by the Securities and Exchange Commission only if the
Company had changed independent auditors and, if it had, only under certain
circumstances.
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is shown in Item 4A "Executive
Officers" and hereby incorporated by reference from the information appearing
under the captions "Proposal One - Election of Directors" in the Company's
definitive proxy statement for the Annual Meeting of Stockholders to be held
April 30, 2003, to be filed with the Securities and Exchange Commission
("Commission") within 120 days of the end of the Company's year ended December
31, 2002.
80
PART III
(continued)
Item 11. EXECUTIVE COMPENSATION
Notwithstanding the foregoing, in accordance with the instructions to Item
402 of Regulations S-K, the information contained in the Company's proxy
statement under the sub-heading "Compensation Committee Report on Executive
Compensation" and "Performance Graph" shall not be deemed to be filed as part of
or incorporated by reference into this Form 10-K.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
EQUITY COMPENSATION PLAN INFORMATION
The information required by this item is hereby incorporated by reference
from the information appearing under the captions "Principal Stockholders and
Security Ownership of Management" and "Equity Compensation Plan Information" in
the Company's definitive proxy statement for the Annual Meeting of Stockholders
to be held April 30, 2003, to be filed with the Commission within 120 days of
the end of the Company's year ended December 31, 2002.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is hereby incorporated by reference
to such information appearing under the caption "Other Information" and "Related
Transactions" in the Company's definitive proxy statement for the Annual Meeting
of Stockholders to be held April 30, 2003, to be filed with the Commission
within 120 days of the end of the Company's year ended December 31, 2002.
Item 14. CONTROLS AND PROCEDURES
Within the 90-day period prior to the filing of this report, the Company
carried out an evaluation, under the supervision and with the participation of
the Company's management, including the chief executive officer and chief
financial officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures (as defined in Rule 13a-14 (c)
under the Securities Exchange Act of 1934). Based upon that evaluation, the
chief executive officer and chief financial officer concluded that the Company's
disclosure controls and procedures are effective in timely alerting them to
material information relating to the Company (including its consolidated
subsidiaries) required to be included in the Company's periodic SEC filings.
There have been no significant changes in our internal controls or in
other factors that could significantly affect these controls subsequent to the
date of their evaluation.
81
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
(1) Financial Statements of Parker Drilling Company and subsidiaries
which are included in Part II, Item 8:
Page
Report of Independent Accountants 35
Consolidated Statement of Operations for the years ended
December 31, 2002, 2001 and 2000 36
Consolidated Balance Sheet as of December 31, 2002 and 2001 37
Consolidated Statement of Cash Flows for the years ended
December 31, 2002, 2001 and 2000 39
Consolidated Statement of Stockholders' Equity for the years
ended December 31, 2002, 2001 and 2000 41
Notes to the Consolidated Financial Statements 42
82
PART IV
(continued)
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(continued)
Page
----
(2) Financial Statement Schedule:
Schedule II - Valuation and qualifying accounts 87
(3) Exhibits:
Exhibit Number Description
- -------------- -----------
3(a) - Corrected Restated Certificate of Incorporation of
the Company, as amended on September 21, 1998
(incorporated by reference to Exhibit 3(c) to the
Company's Annual Report on Form 10-K for the fiscal
year ended August 31, 1998).
3(b) - Rights Agreement dated as of July 14, 1998 between
the Company and Norwest Bank Minnesota, N.A., as
rights agent (incorporated by reference to Form 8-A
filed July 15, 1998.)
3(c) - Amendment No. 1 to the Rights Agreement dated as of
September 22, 1998 between the Company and Norwest
Bank Minnesota, N.A., as rights agent.
3(d) - By-laws of the Company, as amended January 31, 2003.
83
PART IV (continued)
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(continued)
(3) Exhibits: (continued)
Exhibit Number Description
- -------------- -----------
4(a) - Indenture dated as of March 11, 1998 among the
Company, as issuer, certain Subsidiary Guarantors
(as defined therein) and Chase Bank of Texas,
National Association, as Trustee (incorporated by
reference to Exhibit 4.5 to the Company's S-4
Registration Statement No. 333-49089 dated April 1,
1998).
4(b) - Indenture dated as of July 25, 1997, between the
Company and Chase B Bank of Texas, National
Association, f/k/a Texas Commerce Bank National
Association, as Trustee, respecting 5 1/2%
Convertible Subordinated Notes due 2004
(incorporated by reference to Exhibit 4.7 to the
Company's S-3 Registration Statement No. 333-30711).
4(c) - Loan and Security Agreement dated as of October
22, 1999, between the Company and Bank of America,
National Association, as agent for the lenders,
regarding the $50.0 million revolving line of credit
for loans and letters of credit due October 22, 2003
(incorporated by reference to Exhibit 4(c) to the
Annual Report on Form 10-K for the year ended
December 31, 2000).
4(d) - Indenture dated as of May 2, 2002 between the Company
and JPMorgan Chase Bank, as Trustee, respecting the
10.125% Senior Notes due 2009 (incorporated by
reference to Exhibit 4.1 to the Company's S-4
Registration Statement No. 333-91708).
84
PART IV (continued)
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON
FORM 8-K (continued)
(3) Exhibits: (continued)
Exhibit Number Description
- -------------- -----------
10(a) - Amended and Restated Parker Drilling Company Stock
Bonus Plan, effective as of January 1, 1999
(incorporated herein by reference to Exhibit 10(a)
to the Company's Quarterly Report on Form 10-Q for
the three months ended March 31, 1999).*
10(b) - 1994 Parker Drilling Company Deferred Compensation Plan
(incorporated herein by reference to Exhibit 10(h)
to Annual Report on Form 10-K for the year ended
August 31, 1995).*
10(c) - 1994 Non-Employee Director Stock Option Plan
(incorporated herein by reference to Exhibit 10(i)
to Annual Report on Form 10-K for the year ended
August 31, 1995).*
10(d) - 1994 Executive Stock Option Plan (incorporated
herein by reference to Exhibit 10(j) to Annual
Report on Form 10-K for the year ended August 31,
1995).*
10(e) - Third amended and restated 1997 Stock Plan effective
July 24, 2002.*
10(f) - Waiver, Release and Confidentiality Agreement entered
into between James W. Linn and Parker Drilling
Company dated July 17, 2001 (incorporated by
reference to Exhibit 10(f) to Annual Report
on Form 10-K for the year ended December 31, 2001).*
10(g) - Form of Indemnification Agreement entered into between
Parker Drilling Company and each director and
executive officer of Parker Drilling Company, dated
on or about October 15, 2002.*
85
PART IV (continued)
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON
FORM 8-K (continued)
(3) Exhibits: (continued)
10(h) - Form of Employment Agreement entered into between
Parker Drilling Company and each executive officer
of Parker Drilling Company, effective as of
November 2, 2002.*
10(i) - Separation Agreement and Release entered into between
James Davis and Parker Drilling Company effective
September 26, 2002.*
21 - Subsidiaries of the Registrant.
23 - Consent of Independent Accountants.
99.1 - Section 906 Certification
99.2 - Section 906 Certification
* Management Contract, Compensatory Plan or Agreement
(b) Reports on Form 8-K: None.
86
PARKER DRILLING COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Dollars in Thousands)
Column A Column B Column C Column D Column E
- ---------------------------------------------- --------------- ------------ ------------ ------------
Balance Charged
at to cost Balance
beginning and at end of
Classifications of period expenses Deductions period
- ---------------------------------------------- ------------------------------------------------------------------
Year ended December 31, 2002:
Allowance for doubtful accounts
and notes $ 2,988 $ 1,904 $ 129 $ 4,763
Reduction in carrying value of
rig materials and supplies $ 2,406 $ 2,400 $ 1,363 $ 3,443
Deferred tax valuation
allowance $ 9,936 $ (2,927) $ - $ 7,009
Year ended December 31, 2001:
Allowance for doubtful accounts
and notes $ 3,755 $ 360 $ 1,127 $ 2,988
Reduction in carrying value of
rig materials and supplies $ 2,491 $ 1,455 $ 1,540 $ 2,406
Deferred tax valuation
allowance $ 24,939 $ (9,593) $ 5,410 $ 9,936
Year ended December 31, 2000:
Allowance for doubtful accounts
and notes $ 5,677 $ 860 $ 2,782 $ 3,755
Reduction in carrying value of
rig materials and supplies $ 1,539 $ 780 $ (172) $ 2,491
Deferred tax valuation
allowance $ 39,109 $ (6,097) $ 8,073 $ 24,939
87
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PARKER DRILLING COMPANY
By /s/ Robert L. Parker Jr. Date: March 17, 2003
------------------------------
Robert L. Parker Jr.
President and Chief Executive Officer and Director
Pursuant to the requirements of the Securities 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.
Signature Title Date
- --------- ----- ----
By: /s/ Robert L. Parker Chairman of the Board and Director March 17, 2003
---------------------------------
Robert L. Parker
By: /s/ Robert L. Parker Jr. President and Chief Executive March 17, 2003
----------------------------------- Officer and Director
Robert L. Parker Jr. (Principal Executive Officer)
By: /s/ James W. Whalen Senior Vice President and March 17, 2003
---------------------------------- Chief Financial Officer
James W. Whalen (Principal Financial Officer)
By: /s/ Robert F. Nash Senior Vice President and March 17, 2003
-------------------------------- Chief Operating Officer
Robert F. Nash
By: /s/ W. Kirk Brassfield Vice President and March 17, 2003
--------------------------------- Corporate Controller
W. Kirk Brassfield (Principal Accounting Officer)
By: /s/ James E. Barnes Director March 17, 2003
--------------------------------
James E. Barnes
By: /s/ Bernard J. Duroc-Danner Director March 17, 2003
---------------------------------
Bernard J. Duroc-Danner
By: /s/ David L. Fist Director March 17, 2003
---------------------------------
David L. Fist
By: /s/ Dr. Robert M. Gates Director March 17, 2003
---------------------------------
Dr. Robert M. Gates
By: /s/ John W. Gibson Director March 17, 2003
-------------------------------
John W. Gibson
By: /s/ Simon G. Kukes Director March 17, 2003
-------------------------------
Simon G. Kukes
By: /s/ James W. Linn Director March 17, 2003
-------------------------------
James W. Linn
By: /s/ R. Rudolph Reinfrank Director March 17, 2003
---------------------------------
R. Rudolph Reinfrank
88
PARKER DRILLING COMPANY
OFFICER CERTIFICATION
I, Robert L. Parker Jr., certify that:
1. I have reviewed this annual report on Form 10-K of Parker Drilling Company
("the Company");
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;
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
Company as of, and for, the periods presented in this annual report;
4. The Company's other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the Company and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the Company, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the Company's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The Company's other certifying officer and I have disclosed, based on our
most recent evaluation, to the Company's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The Company's other certifying officer and I have indicated in this annual
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 10, 2003
/s/ Robert L. Parker Jr.
-----------------------------
Robert L. Parker Jr.
President and Chief Executive
Officer and Director
89
PARKER DRILLING COMPANY
OFFICER CERTIFICATION
I, James W. Whalen, certify that:
1. I have reviewed this annual report on Form 10-K of Parker Drilling Company
("the Company");
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;
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
Company as of, and for, the periods presented in this annual report;
4. The Company's other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the Company and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the Company, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the Company's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The Company's other certifying officer and I have disclosed, based on our
most recent evaluation, to the Company's auditors and the audit committee of
Company's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the Company's ability to record,
process, summarize and report financial data and have identified for the
Company's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the Company's internal
controls; and
6. The Company's other certifying officer and I have indicated in this annual
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 10, 2003
/s/ James W. Whalen
-----------------------------
James W. Whalen
Senior Vice President and
Chief Financial Officer
90
INDEX TO EXHIBITS
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3(c) - Amendment No. 1 to the Rights Agreement dated as of
September 22, 1998 between the Company and Norwest
Bank Minnesota, N.A., as rights agent.
3(d) - By-laws of the Company, as amended January 31, 2003.
10(e) - Third amended and restated 1997 Stock Plan effective as of
July 24, 2002.
10(g) - Form of Indemnification Agreement entered into between
Parker Drilling Company and each director and
executive officer of Parker Drilling Company, dated on or
about October 15, 2002.
10(h) - Form of Employment Agreement entered into between
Parker Drilling Company and each executive officer
of Parker Drilling Company, effective as of
November 2, 2002.
10(i) - Separation Agreement and Release entered into between
James Davis and Parker Drilling Company effective
September 26, 2002.
21 - Subsidiaries of the Registrant.
23 - Consent of Independent Accountants.
99.1 - Section 906 Certification
99.2 - Section 906 Certification
</Table>
91