NOBLE CORP - 10-K Annual Report

Back to GetFilings.com

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)

FOR THE TRANSITION PERIOD FROM ___________ TO _____________

COMMISSION FILE NUMBER: 0-13857

NOBLE CORPORATION
------------------------------------------------------
(Exact name of registrant as specified in its charter)

CAYMAN ISLANDS 98-0366361
- ------------------------------- ----------------------
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification number)

13135 SOUTH DAIRY ASHFORD, SUITE 800, SUGAR LAND, TEXAS 77478
-------------------------------------------------------------
(Address of principal executive offices) (Zip Code)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (281) 276-6100

Securities registered pursuant to Section 12(b) of the Act:

ORDINARY SHARES, PAR VALUE $.10 PER SHARE NEW YORK STOCK EXCHANGE
PREFERRED SHARE PURCHASE RIGHTS NEW YORK STOCK EXCHANGE
- ----------------------------------------- --------------------------------------------
Title of each class Name of each exchange on which registered

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 registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes [X] No [ ]

Aggregate market value of Ordinary Shares held by nonaffiliates as of
June 28, 2002: $5,098,000,000

Number of Ordinary Shares outstanding as of March 6, 2003: 133,579,505

DOCUMENTS INCORPORATED BY REFERENCE

Listed below are documents parts of which are incorporated herein by
reference and the part of this report into which the document is incorporated:

(1) Proxy statement for the 2003 annual meeting of members - Part III

TABLE OF CONTENTS

FORM 10-K

This report on Form 10-K includes "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, as amended. All statements
other than statements of historical facts included in this Form 10-K, including,
without limitation, statements contained in "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations", regarding our
financial position, business strategy, plans and objectives of management for
future operations, industry conditions, and indebtedness covenant compliance,
are forward-looking statements. Although we believe that the expectations
reflected in such forward-looking statements are reasonable, we cannot assure
you that such expectations will prove to have been correct. Important factors
that could cause actual results to differ materially from our expectations
include, but are not limited to, changes in United States tax laws, or the
enactment of new United States tax laws, that may result in Noble Corporation
being subject to taxation in the United States on its worldwide earnings, other
material changes in the tax laws of the United States or other countries in
which we operate which could increase our effective tax rate, volatility in
crude oil and natural gas prices, the discovery of significant additional oil
and/or gas reserves or the construction of significant oil and/or gas delivery
or storage systems that impact regional or worldwide energy markets, potential
deterioration in the demand for our drilling services and resulting declining
dayrates, changes in our customers' drilling programs or budgets due to factors
discussed herein or due to their own internal corporate events, the cancellation
by our customers of drilling contracts or letter agreements or letters of intent
for drilling contracts or their exercise of early termination provisions
generally found in our drilling contracts, intense competition in the drilling
industry, changes in oil and gas drilling technology or in our competitors'
drilling rig fleets that could make our drilling rigs less competitive or
require major capital investment to keep them competitive, political and
economic conditions in the United States and in international markets where we
operate, acts of war or terrorism and the aftermath of the September 11, 2001
terrorist attacks on the United States, cost overruns or delays on shipyard
repair, maintenance, conversion or upgrade projects, adverse weather (such as
hurricanes or monsoons) and seas, operational risks (such as blowouts and
fires), limitations on our insurance coverage, and requirements and potential
liability imposed by governmental regulation of the drilling industry (including
environmental regulation). All of the foregoing risks and uncertainties are
beyond our ability to control, and in many cases, we cannot predict the risks
and uncertainties that could cause our actual results to differ materially from
those indicated by the forward-looking statements. When used in this Form 10-K,
the words "believes", "anticipates", "expects", "plans" and similar expressions
as they relate to the Company or its management are intended to identify
forward-looking statements.

PART I

ITEM 1. BUSINESS

GENERAL

We are a leading provider of diversified services for the oil and gas
industry. We perform contract drilling services with our fleet of 55 offshore
drilling units located in key markets worldwide. Our fleet of floating deepwater
units consists of 13 semisubmersibles and three dynamically positioned
drillships, seven of which are designed to operate in water depths greater than
5,000 feet. Our premium fleet of 36 independent leg, cantilever jackup rigs
includes 22 units that operate in water depths of 300 feet or greater, four of
which operate in water depths of 360 feet or greater, and 11 units that operate
in water depths up to 250 feet. In addition, our fleet includes three
submersible drilling units. Nine of our drilling units are capable of operating
in harsh environments. Approximately 70 percent of the fleet is currently
deployed in international markets, principally including the North Sea, Brazil,
West Africa, the Middle East, Mexico and India. During 2000, we also operated in
Venezuela. We provide technologically advanced drilling-related products and
services designed to create value for our customers. We also provide labor
contract drilling services, well site and project management services, and
engineering services.

Noble Corporation, a Cayman Islands exempted company limited by shares
(which we sometimes refer to in this report as "Noble"), became the successor to
Noble Drilling Corporation, a Delaware corporation (which we sometimes refer to
as "Noble Drilling") that was organized in 1939, as part of the internal
corporate restructuring of

1

Noble Drilling and its subsidiaries during 2002. See "Corporate Restructuring"
below for more information on this restructuring. Noble and its predecessors
have been engaged in the contract drilling of oil and gas wells for others
domestically since 1921 and internationally during various periods since 1939.
As used herein, unless otherwise required by the context, the term "Noble"
refers to Noble Corporation and the terms "Company", "we", "our" and words of
similar import refer to Noble and its consolidated subsidiaries. The use herein
of such terms as group, organization, we, us, our and its, or references to
specific entities, is not intended to be a precise description of corporate
relationships.

BUSINESS STRATEGY

Although the deepwater drilling market is currently experiencing
near-term softness due to an increased supply of deepwater rigs, both the level
of drilling activity and the number of announced discoveries in water depths
greater than 5,000 feet have increased substantially in recent years, thus
increasing the demand for rigs capable of drilling in these water depths. As
such, in recent years we have focused on increasing the number of rigs in our
fleet capable of deepwater offshore drilling. We have incorporated this focus
into our broader, long-standing business strategy to actively expand our
international and offshore deepwater capabilities through acquisitions, rig
upgrades and modifications, and to deploy assets in important geological areas.

The offshore contract drilling industry has, in recent years,
experienced a series of asset sales and consolidations among drilling
contractors, and we expect this trend to continue as drilling contractors
position themselves strategically in the market. From time to time, we discuss
asset transactions or business combinations with others, and we intend to
continue to consider business opportunities that we believe promote our business
strategy.

In addition, as part of our strategy, we have focused on the continued
development of technological applications for the drilling industry. Our Noble
Engineering & Development Limited ("NED"), Maurer Technology Incorporated
("Maurer") and newly acquired downhole technology subsidiaries are engaged in
this activity. (See "Business Development During 2002" below for information
regarding our newly acquired downhole technology subsidiaries.)

BUSINESS DEVELOPMENT DURING 2002

As part of our strategy to expand our international operations, we
moved four jackup rigs to Mexico from the U.S. Gulf of Mexico for long-term
contracts with Petroleos Mexicanos ("Pemex") during the latter part of 2002. The
Noble Gene Rosser and Noble Sam Noble commenced contracts with Pemex in
September and October, respectively, while the Noble Johnnie Hoffman and Noble
John Sandifer commenced contracts with Pemex in November. We also recently
entered into letters of intent for long-term contracts with Pemex for the
Noble Leonard Jones and Noble Earl Frederickson. We expect to commence these
contracts for the Noble Leonard Jones and Noble Earl Frederickson in March
2003 and April 2003, respectively.

In addition, we purchased several drilling units during 2002. On
December 12, 2002, we purchased two jackup drilling rigs, the Trident III and
Dhabi II, from a subsidiary of Schlumberger Limited for an aggregate purchase
price of $95,000,000 in an all cash transaction. These units are operating in
the United Arab Emirates under contracts expiring in 2004. We also entered into
option agreements with this subsidiary of Schlumberger that give us the right to
purchase two additional premium jackup rigs, the Trident XVIII and Trident XIX.
These units are currently operating in Iran and our right to exercise these
options will commence following the completion of their existing contracts and
their mobilization to the United Arab Emirates, which is expected to be May 2003
and July 2003 for the Trident XVIII and Trident XIX, respectively. We paid
$24,900,000 for these options and would pay an additional exercise price of
$58,100,000 to purchase both units.

On March 27, 2002, we purchased two semisubmersible baredecks, Bingo
9000 Rig 3 and Bingo 9000 Rig 4, from subsidiaries of Ocean Rig ASA ("Ocean
Rig") for an aggregate purchase price of $45,000,000 in an all cash transaction.

2

On March 26, 2002, we purchased two semisubmersible drilling rigs, the
Noble Lorris Bouzigard (ex Transocean 96) and Noble Therald Martin (ex
Transocean 97), from subsidiaries of Transocean Inc. for an aggregate purchase
price of $31,000,000 in an all cash transaction. Each unit is a pentagon
designed semisubmersible currently capable of operating in water depths up to
2,350 feet and was upgraded in 1997. We recently completed an upgrade to the
living quarters and drilling equipment on the Noble Lorris Bouzigard and the
unit is currently operating under contract in the Gulf of Mexico. We are
currently upgrading the living quarters and drilling equipment on the Noble
Therald Martin. This unit's upgrade will be completed in the second quarter of
2003 and the unit will be equipped with Noble's proprietary aluminum alloy
riser, which will allow it to drill in up to 4,000 feet of water. We plan to
deploy aluminum alloy riser on the Noble Lorris Bouzigard during the third
quarter of 2003, which will enable it also to drill in up to 4,000 feet of
water.

On May 3, 2002, as part of our strategy to expand our technology
initiative, we made several acquisitions. We acquired all of the shares of
WELLDONE Engineering GmbH ("WELLDONE") for $5,750,000 in cash. We agreed to pay
up to an additional $3,500,000 provided WELLDONE's tools achieve certain
operational and financial milestones during the period through May 3, 2004.
WELLDONE's primary asset is its ownership in the "Well Director(TM)", an
automatic rotary steerable drilling system, which was designed by and is
manufactured and marketed through DMT WELLDONE Drilling Services GmbH ("DMT
WELLDONE"). As a result of our acquisition of WELLDONE, we acquired WELLDONE's
50 percent joint venture interest in DMT WELLDONE, which is further described
below. We paid $2,650,000 to Deutsche Montan Technologie GmbH ("DMT"), the other
joint venturer in DMT WELLDONE, for the remaining 50 percent interest in the
joint venture.

In connection with the above described transaction, we also acquired 24
Well Director(TM) drilling tools and related assets owned by Phoenix Technology
Services, Ltd. ("Phoenix") for $6,000,000 in cash. We agreed to pay up to an
additional $3,000,000 provided certain operating performance milestones are
achieved during the period through May 3, 2005. In the transaction we also
acquired from Phoenix its worldwide marketing rights to the Well Director(TM)
drilling tools.

Pursuant to a related agreement, we and DMT each committed to fund
2,100,000 Euros to a new joint venture in which each party has a 50 percent
interest. The joint venture will in turn use such funds to retain DMT to conduct
research and development. This joint venture will own the intellectual property
rights of all new technology developed.

CORPORATE RESTRUCTURING

On April 30, 2002, Noble became the successor to Noble Drilling as part
of the internal corporate restructuring of Noble Drilling and its subsidiaries.
This restructuring was approved by the stockholders of Noble Drilling at its
2002 annual stockholders meeting. The proposal to adopt the restructuring passed
with 106,694,424 shares voted in favor of the proposal (representing 96.4
percent of the shares voted on the proposal). The restructuring was accomplished
through the merger of an indirect, wholly-owned subsidiary of Noble Drilling
with and into Noble Drilling. Noble Drilling survived the merger and is now an
indirect, wholly-owned subsidiary of Noble. In addition, as a result of the
merger, all of the outstanding shares of common stock (and the related preferred
stock purchase rights) of Noble Drilling were exchanged for ordinary shares (and
related preferred share purchase rights) of Noble. Noble and its subsidiaries,
including Noble Drilling, continue to conduct the businesses previously
conducted by the Noble Drilling corporate group prior to the merger. We
accounted for the restructuring as a reorganization of entities under common
control. Consequently, the consolidated amounts of assets, liabilities and
shareholders' equity did not change as a result of the restructuring.

Noble Drilling sought stockholder approval of and effected the
restructuring as a means to remain competitive in the global marketplace to
provide diversified services to the oil and gas industry. Under the restructured
organization, we gain flexibility to reduce our worldwide corporate effective
tax rate, increase the operational efficiencies of our business, and create a
corporate structure that is generally more favorable for expansion of our
business. Additionally, we believe Noble could be a more attractive investment
alternative to a wider range of investors.

3

For the year ended December 31, 2002, 65 percent of our revenues and 86
percent of our net income was derived from drilling operations outside of the
United States. Our restructuring was in part driven by inequitable treatment
under current U.S. tax laws, which impose taxes on the worldwide income of U.S.
companies. This method of taxation places U.S.-based multinationals at a
competitive disadvantage. The parent companies of certain of our competitors,
including our two largest competitors, are incorporated in the Cayman Islands
and other non-U.S. countries that impose either no tax or tax at rates
substantially less than the United States.

As previously disclosed and widely reported in the media, during the
107th Congress several bills had been introduced in the U.S. House of
Representatives and the U.S. Senate which dealt with various aspects of
corporate "inversions". Although previously proposed legislation, if enacted in
its form as originally filed, would have substantially reduced or eliminated the
benefits of the restructuring to Noble, other proposed legislation would have
allowed Noble to maintain the benefits of the restructuring. Proposed
legislation was also directed towards leveling the playing field with respect to
provisions in the U.S. Internal Revenue Code that put U.S. companies competing
in a global marketplace at a competitive disadvantage.

Legislation similar to bills proposed in 2002 has been, or likely will
be, introduced in the 108th Congress. Our consolidated financial statements for
the year ended December 31, 2002 include a reduction in the income tax provision
of $9,000,000 for tax benefits attributable to this restructuring.

DRILLING CONTRACTS

We typically employ each drilling unit under an individual contract.
Although the final terms of the contracts are the result of our negotiations
with our customers, many contracts are awarded based upon competitive bidding.
Our drilling contracts generally contain the following terms:

o a term extending over a specific period of time or the period
necessary to drill one or more wells (in general, we seek to
have a reasonable balance of short- and long-term contracts to
minimize the impact of a decline in the market, while
obtaining the upside of increasing market prices in a rising
market);

o terms permitting early termination of the contract by the
customer (1) if the unit is lost or destroyed; or (2) if
operations are suspended for a specified period of time due to
either breakdown of major equipment or "force majeure" events
beyond our control and the control of the customer;

o options in favor of the customer to drill one or more
additional wells, generally upon advance notice to us;

o payment of compensation to us (generally in U.S. Dollars) on a
"daywork" basis, so that we receive a fixed amount for each
day ("dayrate") that the drilling unit is operating under
contract (lower rates or no compensation is payable during
periods of equipment breakdown and repair or adverse weather
or in the event operations are interrupted by other
conditions, some of which may be beyond our control); and

o payment by us of the operating expenses of the drilling unit,
including labor costs and the cost of incidental supplies.

The terms of some of our drilling contracts permit early termination of
the contract by the customer, without cause, generally exercisable upon advance
notice to us. The terms may also require an early termination payment by the
customer.

During times of depressed market conditions, our customers may seek to
avoid or reduce their obligations under term drilling contracts or letter
agreements or letters of intent for drilling contracts. A customer may no longer
need a rig, due to a reduction in its exploration, development or production
program, or it may seek to obtain a comparable rig at a lower dayrate.

4

Seventeen of our rigs are contracted for the remainder of 2003. We
anticipate that the primary terms of the current contracts on 28 of our rigs
will expire at varying times in 2003, subject to options to extend in the case
of 18 contracts. Our remaining rigs are either available for service or in a
shipyard for repair, refurbishment or upgrade.

Many contracts allow us to recover our mobilization and demobilization
costs associated with moving a drilling unit from one location to another. When
market conditions require us to bear these costs, our operating margins are
accordingly reduced. We cannot predict our ability to recover these costs in the
future. For shorter moves such as "field moves", our customers have generally
agreed to bear the costs of moving the unit by paying us a reduced dayrate or
"move rate" while the unit is being moved.

OFFSHORE DRILLING OPERATIONS

Our offshore contract drilling operations, which accounted for
approximately 95 percent, 95 percent and 86 percent of operating revenues for
the years ended December 31, 2002, 2001 and 2000, respectively, are conducted
worldwide. Our offshore drilling fleet consists of 55 units. See "Drilling
Fleet" in "Item 2. Properties." Our principal regions of contract drilling
operations include the Gulf of Mexico, North Sea, Brazil, West Africa, the
Middle East, Mexico and India. In 2002, Royal Dutch/Shell Group and Petroleo
Brasiliero S.A. accounted for approximately 15 percent and 12 percent,
respectively, of our total operating revenues. No other single customer
accounted for more than 10 percent of our total operating revenues.

INTERNATIONAL CONTRACT DRILLING

Our contract drilling services revenues from international sources
accounted for approximately 68 percent, 52 percent and 49 percent of our total
contract drilling services revenues for 2002, 2001 and 2000, respectively. In
2002, approximately 63 percent of our international contract drilling services
revenues was derived from contracts with large cap (equity market capitalization
greater than $4 billion) companies, 33 percent was derived from contracts with
government-owned companies and the remaining 4 percent was derived from other
independent operators.

DOMESTIC CONTRACT DRILLING

Contract drilling services revenues generated in the U.S. accounted for
approximately 32 percent, 48 percent and 51 percent of our total contract
drilling services revenues for 2002, 2001 and 2000, respectively. In 2002,
approximately 81 percent of our domestic contract drilling revenues was derived
from contracts with large cap companies and the remaining 19 percent was derived
from contracts with other independent operators.

LABOR CONTRACTS

Our offshore operations also include services we perform under labor
contracts for drilling and workover activities covering six rigs operating in
the U.K. North Sea and two rigs under a labor contract (the "Hibernia Project")
off the east coast of Canada. These rigs are not owned or leased by us. Under
our labor contracts, we provide the personnel necessary to manage and perform
the drilling operations from drilling platforms owned by the operator. With the
exception of the Hibernia Project, which is operated under a five-year agreement
that was extended during 2002 and expires in 2007, our labor contracts are
generally renewable on an annual basis. After drilling operations are completed,
workover operations usually become an important element of each platform's
activity. Drilling contractor crews will, therefore, typically remain on the
platform until a field is depleted.

5

TECHNOLOGY, ENGINEERING SERVICES AND PROJECT MANAGEMENT

Our technology initiative focuses on the design and development of
drilling products, drilling related software programs and technical solutions to
enhance drilling efficiency. These functions are performed by our NED and Maurer
subsidiaries. In addition, through our WELLDONE and Phoenix acquisitions we will
begin operating our Well Director(TM) automatic rotary steerable drilling system
and continue to conduct research and development on downhole technologies in
2003.

We also provide engineering services, which includes the design of
drilling equipment for offshore development. We work on a contract basis with
operators and prime construction contractors of drilling and production
platforms in the design of drilling equipment configurations aimed at optimizing
the operational efficiency of developmental drilling by maximizing platform
space utilization and load capability.

In October 2000, our Triton Engineering subsidiary ("Triton") revised
its business model to focus on well site management, project management and
technical services. Turnkey drilling, Triton's major revenue source prior to
revising its business model, involved Triton's coordination of all equipment,
materials, services and management to drill a well to a specified depth, for a
fixed price. Under turnkey drilling contracts, Triton bore the financial risk of
delays in the completion of the well. Due to its revised business model, Triton
did not complete any turnkey wells in 2002 or 2001, compared to 20 wells
completed in 2000. No revenues from turnkey drilling services were recognized in
2002 and 2001, while these operations represented 9 percent of our consolidated
operating revenues in 2000.

COMPETITION AND RISKS

The contract drilling industry is a highly competitive and cyclical
business characterized by high capital and maintenance costs. We believe that
competition for drilling contracts will continue to be intense for the
foreseeable future. Certain competitors may have access to greater financial
resources than we do.

Competition in contract drilling involves numerous factors, including
price, rig availability and suitability, experience of the workforce,
efficiency, condition of equipment, operating integrity, reputation, industry
standing and customer relations. We believe that we compete favorably with
respect to all of these factors. Competition is primarily on a regional basis
and may vary significantly by region at a particular time. Demand for offshore
drilling equipment also depends on the exploration and development programs of
oil and gas producers, which in turn are influenced by the financial condition
of such producers, by general economic conditions and prices of oil and gas,
and, from time to time, by political considerations and policies.

We follow a policy of keeping our equipment well maintained and
technologically competitive. However, our equipment could be made obsolete by
the development of new techniques and equipment. In addition, industry-wide
shortages of supplies, services, skilled personnel and equipment necessary to
conduct our business occur from time to time. We cannot assure you that any such
shortages experienced in the past would not occur again or that any shortages,
to the extent currently existing, will not continue or worsen in the future.

Our results of operations depend on the levels of activity in offshore
oil and gas exploration, development and production in markets worldwide.
Historically, oil and gas prices and market expectations of potential changes in
these prices have significantly affected that level of activity. These prices
are extremely volatile. Despite generally higher oil prices in 2002 as compared
to 2001, drilling activity in many international markets, which are influenced
more by oil prices than natural gas prices, remained flat during 2002. We
believe that operators in international markets were reluctant to increase
drilling activity in 2002, despite these higher prices, due to the uncertainty
surrounding the worldwide economy and the political unrest in the Middle East
and Venezuela, which contributed to the higher oil prices.

Natural gas prices also rose during 2002 as inventory storage has
fallen below average historical levels. The decline in natural gas inventory
storage is attributable to lower North American natural gas production in 2002
and increased demand for natural gas due to winter temperatures that were colder
than the previous year. Although natural gas prices continued to rise during
2002, operators on average have not increased drilling activities. We

6

believe this is due to the uncertainty surrounding the world economy. The
reduced drilling activity in the U.S. Gulf of Mexico has resulted in continued
depressed utilization rates and dayrates for drilling rigs in that region.

Demand for drilling services depends on a variety of economic and
political factors, including worldwide demand for oil and gas, the ability of
the Organization of Petroleum Exporting Countries ("OPEC") to set and maintain
production levels and pricing, the level of production of non-OPEC countries and
the policies of the various governments regarding exploration and development of
their oil and gas reserves.

We believe that a significant decrease from recent historical average
oil and gas prices could depress the level of exploration and production
activity and result in a corresponding decline in demand for our services.
Furthermore, oil companies continue to work through the effects of industry
consolidation, which has inhibited capital spending on exploration and
development. We expect that further consolidation among our customer base would
dampen drilling activity levels near-term.

For the foregoing reasons, we cannot predict the future level of demand
for our drilling services or future conditions in the offshore contract drilling
industry.

Our operations are subject to the many hazards inherent in the drilling
business, including blowouts, cratering, fires and collisions or groundings of
offshore equipment. In addition, our operations are subject to damage or loss
from adverse weather and seas. These hazards could cause personal injury and
loss of life, suspend drilling operations or seriously damage or destroy the
property and equipment involved and, in addition to causing environmental
damage, could cause substantial damage to oil and natural gas producing
formations. Although we maintain insurance against many of these hazards, our
insurance is subject to deductibles. It also excludes certain matters from
coverage, such as loss of earnings on certain rigs. Also, we generally obtain
indemnification from our customers for environmental damage with respect to
offshore drilling.

Our international operations are also subject to certain political,
economic and other uncertainties including, among others, risks of war,
terrorism and civil disturbances, expropriation, nationalization, renegotiation
or modification of existing contracts, taxation policies, foreign exchange
restrictions, international monetary fluctuations and other hazards arising out
of foreign governmental sovereignty over certain areas in which we conduct
operations. We have sought to obtain, where economical, insurance against
certain political risks. However, we cannot assure you that this insurance will
always be available to us or, if available, will cover all losses that we may
incur in respect of foreign operations.

GOVERNMENTAL REGULATION AND ENVIRONMENTAL MATTERS

Many aspects of our operations are affected by domestic and foreign
political developments and are subject to numerous governmental regulations that
may relate directly or indirectly to the contract drilling industry. The
regulations applicable to our operations include provisions that regulate the
discharge of materials into the environment or require remediation of
contamination under certain circumstances. Generally, these environmental laws
and regulations impose "strict liability". This means that we could be liable
without regard to our negligence or fault. Such environmental laws and
regulations may expose us to liability for the conduct of, or conditions caused
by, others, or for any of our acts, even if they complied with all applicable
laws in effect at the time we acted.

The U.S. Oil Pollution Act of 1990 ("OPA `90") and regulations
thereunder impose certain additional operational requirements on our domestic
offshore rigs and govern liability for leaks, spills and blowouts involving
pollutants. Regulations under OPA `90 require owners and operators of rigs in
United States waters to maintain certain levels of financial responsibility. We
monitor these regulations and do not believe that they are likely to have a
material adverse effect on our financial condition or results of operations. We
have made and will continue to make expenditures to comply with environmental
requirements. To date we have not expended material amounts in order to comply
and we do not believe that our compliance with such requirements will have a
material adverse effect upon our results of operations or competitive position
or materially increase our capital expenditures. Although these requirements
impact the energy and energy services industries, generally they do not appear
to affect us any differently or to any greater or lesser extent than other
companies in the energy services industry.

7

The modification of existing laws or regulations or the adoption of new
laws or regulations curtailing exploratory or developmental drilling for oil and
gas for economic, environmental or other reasons could materially and adversely
affect our operations by limiting drilling opportunities.

EMPLOYEES

At December 31, 2002, we had 3,747 employees, of whom approximately 50
percent were engaged in international operations and approximately 50 percent
were engaged in domestic operations. We are not a party to any collective
bargaining agreements that are material. We consider our employee relations to
be satisfactory.

FINANCIAL INFORMATION ABOUT FOREIGN AND DOMESTIC OPERATIONS

Information regarding our operating revenues and identifiable assets
attributable to each of our geographic areas of operations for the last three
fiscal years is presented in Note 16 to our consolidated financial statements
included in this Annual Report on Form 10-K.

AVAILABLE INFORMATION

Our annual reports on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are
available free of charge at our internet website at http://www.noblecorp.com.
These filings are also available to the public at the Securities and Exchange
Commission's ("SEC") Public Reference Room at 450 Fifth Street, NW, Washington,
DC 20549. The public may obtain information on the operation of the Public
Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the
SEC are also available on the SEC internet website at http://www.sec.gov.

ITEM 2. PROPERTIES

DRILLING FLEET

Our offshore drilling rig fleet consists of 55 units comprising 13
semisubmersibles (including five Noble EVA-4000(TM) semisubmersibles), three
drillships, 36 jackup rigs and three submersibles. The rig count includes one
drillship and one jackup unit in which we have partial ownership interests
through joint ventures and one jackup rig operated pursuant to a long-term lease
("bareboat charter") agreement. Each type of rig is described further below.
There are several factors that determine the type of rig most suitable for a
particular job, the most significant of which include the water depth and bottom
conditions at the proposed drilling location, whether the drilling is being done
over a platform or other structure, and the intended well depth.

SEMISUBMERSIBLES

Our semisubmersible fleet consists of 13 units. Among the thirteen are
five units that have been converted to Noble EVA-4000(TM) semisubmersibles and
three Friede & Goldman 9500 Enhanced Pacesetter semisubmersibles. Also included
in this fleet are two Pentagone 85 semisubmersibles, two Bingo 9000 baredeck
hulls, and one semisubmersible capable of operating in harsh environments.
Semisubmersibles are floating platforms which, by means of a water ballasting
system, can be submerged to a predetermined depth so that a substantial portion
of the hull is below the water surface during drilling operations. These units
maintain their position over the well through the use of either a fixed mooring
system or a dynamic positioning system and can drill in many areas where jackup
rigs can also drill. However, semisubmersibles normally require water depth of
at least 200 feet in order to conduct operations. Our semisubmersibles are
designed to work in water depths of up to 8,900 feet, depending on the unit.
Semisubmersibles are typically more expensive to construct and operate than
jackup rigs.

8

DYNAMICALLY POSITIONED DRILLSHIPS

We have three dynamically positioned drillships in the fleet.
Drillships are ships that are equipped for drilling and are typically
self-propelled. Drillships are positioned over the well through use of either an
anchoring system or a computer controlled dynamic positioning system. Our two
wholly-owned drillships, the Noble Leo Segerius and Noble Roger Eason, are
capable of drilling in water depths up to 5,000 feet and 6,000 feet,
respectively. The Noble Muravlenko, in which we own an 82 percent interest
through a joint venture, is capable of drilling in water depths up to 4,000
feet.

JACKUP RIGS

We have 36 jackup rigs in the fleet, including one in which we own a 50
percent interest through a joint venture and one that we operate pursuant to a
long-term bareboat charter agreement. Jackup rigs are mobile, self-elevating
drilling platforms equipped with legs which can be lowered to the ocean floor
until a foundation is established to support the drilling platform. The rig hull
includes the drilling rig, jacking system, crew quarters, loading and unloading
facilities, storage areas for bulk and liquid materials, helicopter landing deck
and other related equipment. All of our jackup rigs are independent leg (i.e.,
the legs can be raised or lowered independently of each other), cantilevered
rigs. A cantilevered jackup has a feature that permits the drilling platform to
be extended out from the hull, allowing it to perform drilling or workover
operations over pre-existing platforms or structures. Moving a rig to the drill
site involves jacking up its legs until the hull is floating on the surface of
the water. The hull is then towed to the drill site by tugs and the legs are
jacked down to the ocean floor. The jacking operation continues until the hull
is raised out of the water and drilling operations are conducted with the hull
in its raised position. Our jackup rigs are capable of drilling to a maximum
depth of 25,000 feet in water depths ranging between eight and 390 feet,
depending on the jackup rig. Our premium fleet of jackup rigs includes 22 units
that are capable of operating in water depths of 300 feet or greater, four of
which are capable of operating in water depths of 360 feet or greater, and 11
units that operate in water depths up to 250 feet. Eight of our jackup rigs are
capable of operating in harsh environments.

SUBMERSIBLES

We have three submersibles in the fleet. Submersibles are mobile
drilling platforms which are towed to the drill site and submerged to drilling
position by flooding the lower hull until it rests on the sea floor, with the
upper deck above the water surface. Our submersibles are capable of drilling to
a maximum depth of 25,000 feet in water depths ranging between 12 and 85 feet,
depending on the submersible.

The following table sets forth certain information concerning our
drilling rig fleet at March 13, 2003. The table does not include eight rigs
owned by operators for which we had labor contracts as of March 13, 2003. We
operate and, unless otherwise indicated, own all of the rigs included in the
table.

9

DRILLING FLEET

See footnotes on the following page.

10

FOOTNOTES TO DRILLING FLEET

(T) Denotes Top Drive.

(1) Rigs designated with an "R" were modified, refurbished or otherwise
upgraded in the year indicated by capital expenditures in an amount
deemed material by management.

(2) Rigs listed as "active" were operating under contract; rigs listed as
"available" were available for bidding; rigs listed as "contracted"
have signed contracts or have letters of intent with operators but have
not begun operations; rigs listed as "shipyard" are in a shipyard for
repair, refurbishment or upgrade.

(3) Harsh environment capability.

(4) Water depth rating is subsequent to the rig's planned upgrade.

(5) Water depth rating is utilizing aluminum alloy riser.

(6) We operate the unit and own an 82 percent interest in the unit through
a joint venture.

(7) Although currently located in the U.S. Gulf of Mexico, the rig has been
contracted for work in Mexico, which is expected to begin in March
2003.

(8) Although designed for a water depth rating of 390 feet of water in a
non-harsh environment, the rig is currently equipped with legs adequate
to drill in approximately 180 feet of water. We own the additional
legs required to extend the drilling depth capability to 390 feet of
water.

(9) We have operating control of the unit pursuant to a long-term bareboat
charter agreement.

(10) Although designed for a water depth rating of 300 feet of water, the
rig is currently equipped with legs adequate to drill in approximately
250 feet of water. We own the additional legs required to extend the
drilling depth capability to 300 feet of water.

(11) We own a 50 percent interest in the unit through a joint venture.

(12) Although designed for a water depth rating of 300 feet of water, the
rig is currently equipped with legs adequate to drill in approximately
250 feet of water.

(13) Although currently located in the U.S. Gulf of Mexico, the rig has
been contracted for work in Mexico, which is expected to begin in
April 2003.

11

FACILITIES

Our principal executive offices are located in Sugar Land, Texas, and
are leased through June 2011. We also lease administrative and marketing
offices, and sites used primarily for storage, maintenance and repairs for
drilling rigs and equipment, in St. Michael, Barbados; New Orleans and Lafitte,
Louisiana; Leduc, Alberta and St. John's, Newfoundland, Canada; Lagos and Port
Harcourt, Nigeria; Aberdeen, Scotland; Stavanger, Norway; Ciudad Ojeda,
Venezuela; Del Carmen, Mexico; Doha, Qatar; Abu Dhabi, U.A.E.; Beverwijk, The
Netherlands; Macae, Brazil; Essen and Lachendorf, Germany; and Esjberg, Denmark.
We own certain tracts of land, including office and administrative buildings and
warehouse facilities in Bayou Black, Louisiana; Aberdeen, Scotland; and Grand
Cayman, Cayman Islands.

ITEM 3. LEGAL PROCEEDINGS

There are no material pending legal proceedings to which we are a party
or of which our property is the subject. We are involved in certain routine
litigation incidental to our business.

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

Not applicable.

12

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information as of March 6, 2003
with respect to our executive officers:

James C. Day has served as Chairman of the Board of Noble since October
22, 1992 and as Chief Executive Officer since January 1, 1984, and he served as
President from January 1, 1984 to January 1, 1999. From January 1983 until his
election as President and Chief Executive Officer, Mr. Day served as Vice
President of Noble Drilling. Prior to 1983, Mr. Day served as Vice President and
Assistant Secretary of Noble Affiliates, Inc. He has been a director of Noble
since 1984. Mr. Day is also a director of Global Industries, Ltd. and Noble
Affiliates, Inc. and a trustee of The Samuel Roberts Noble Foundation, Inc.

Robert D. Campbell has served as President of Noble since January 1,
1999 and as a director since February 4, 1999. Prior to January 1, 1999, Mr.
Campbell practiced corporate/securities law as a senior shareholder with the
firm of Thompson & Knight, P.C. and served as general counsel to Noble Drilling
for more than five years.

Mark A. Jackson has served as Senior Vice President and Chief Financial
Officer of Noble since September 1, 2000. From May 1999 to August 2000, Mr.
Jackson served as Executive Vice President and Chief Financial Officer for Santa
Fe Snyder Corporation, an oil and gas exploration and production company. From
August 1997 to May 1999, he served as Senior Vice President and Chief Financial
Officer of Snyder Oil Corporation, an oil and gas exploration and production
company. Prior to August 1997, Mr. Jackson served consecutively in the positions
of Vice President & Controller, Vice President - Finance and Vice President &
Chief Financial Officer of Apache Corporation, an oil and gas exploration and
production company, beginning in 1988.

Danny W. Adkins has served as Senior Vice President - Operations of
Noble since April 2002. Prior to that, he held the same position with Noble
Drilling International (Cayman) Ltd. since August 2000. From March 1997 to
August 2000, Mr. Adkins served consecutively as Vice President - Engineering and
Senior Vice President - Engineering for Noble Drilling Services Inc. From
September 1994 to March 1997, he served as Vice President - Operations for Noble
Drilling Services Inc. Prior to September 1994, Mr. Adkins served consecutively
in the positions of Manager of Engineering and Vice President - Operations for a
predecessor subsidiary of Noble, beginning in December 1990.

Julie J. Robertson has served as Senior Vice President - Administration
of Noble since July 2001 and as Corporate Secretary of Noble since December
1993. Ms. Robertson served as Vice President - Administration of Noble Drilling
from April 1996 to July 2001. In September 1994, Ms. Robertson became Vice
President - Administration of Noble Drilling Services Inc. From January 1989 to
September 1994, Ms. Robertson served consecutively as Manager of Benefits and
Director of Human Resources for Noble Drilling Services Inc. Prior to 1989, Ms.
Robertson served consecutively in the positions of Risk and Benefits Manager and
Marketing Services Coordinator for a predecessor subsidiary of Noble, beginning
in 1979.

13

PART II

ITEM 5. MARKET FOR REGISTRANT'S ORDINARY SHARES AND RELATED SHAREHOLDER MATTERS

Noble's ordinary shares are listed and traded on the New York Stock
Exchange under the symbol "NE". The following table sets forth for the periods
indicated the high and low sales prices of our ordinary shares:

We have not paid any cash dividends on our ordinary shares, and Noble
Drilling did not pay any cash dividends on shares of its common stock since it
became a publicly held corporation in October 1985. We do not anticipate paying
dividends on our ordinary shares at any time in the foreseeable future.

At March 6, 2003, there were 1,653 record holders of ordinary shares.

During 2002, we sold European-style put options covering 1,300,000 of
our ordinary shares in 12 separate private transactions (11 transactions of
100,000 put options each and another transaction of 200,000 put options). The
options gave the holder the right to require us to purchase our ordinary shares
from the holder at their respective exercise prices on their respective
expiration dates. If we were required to purchase the shares covered by the
options, we had the option to settle in cash or net shares of Noble. The strike
price under each option represented between 90 and 95 percent of the spot price
of the ordinary shares at the date of the transaction.

The following table sets forth certain information with respect to each
of these 12 transactions:

(1) 100,000 ordinary shares were issued upon the exercise of these put options.

14

ITEM 6. SELECTED FINANCIAL DATA

- ----------

(1) During 2002, we adopted Emerging Issues Task Force No. 01-14, Income
Statement Characterization of Reimbursements Received for Out-of-Pocket
Expenses Incurred ("EITF 01-14"). EITF 01-14 requires that "out-of-pocket"
expenses incurred be included in direct costs and the reimbursements
received from customers related to such expenses be included in operating
revenues. Accordingly, pursuant to EITF 01-14, we have reclassified the
reimbursements from customers that were recorded as a reduction to direct
costs to operating revenues for all periods presented. The impact on
operating revenues and direct costs was an increase of $27,431,000,
$15,624,000, $9,695,000 and $12,231,000 for 2001, 2000, 1999 and 1998,
respectively. This adoption had no impact on operating income or net
income.

(2) The 1999 amount includes a non-recurring restructuring charge of
$4,861,000, net of tax, related to early retirement packages offered to a
number of domestic employees and the relocation of our Lafayette, Louisiana
office to Sugar Land, Texas.

(3) Consists of long-term debt ($589,562,000 at December 31, 2002), and
short-term debt and current maturities of long-term debt ($80,577,000 at
December 31, 2002). The December 31, 2002 amount includes $38,401,000
principal amount of fixed rate senior secured notes issued by an indirect,
wholly-owned subsidiary of Noble, which notes are non-recourse except to
the issuer thereof.

15

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following discussion is intended to assist you in understanding our
financial position as of December 31, 2002 and 2001, and our results of
operations for each of the three years in the period ended December 31, 2002.
You should read the accompanying consolidated financial statements and their
notes in conjunction with this discussion.

BUSINESS ENVIRONMENT

Demand for drilling services depends on a variety of economic and
political factors, including worldwide demand for oil and gas, the ability of
OPEC to set and maintain production levels and pricing, the level of production
of non-OPEC countries and the policies of the various governments regarding
exploration and development of their oil and gas reserves.

Our results of operations depend on the levels of activity in offshore
oil and gas exploration, development and production in markets worldwide.
Historically, oil and gas prices and market expectations of potential changes in
these prices have significantly affected that level of activity. These prices
are extremely volatile. Despite generally higher oil prices in 2002 as compared
to 2001, drilling activity in many international markets, which are influenced
more by oil prices than natural gas prices, remained flat during 2002. We
believe that operators in international markets were reluctant to increase
drilling activity in 2002, despite these higher prices, due to the uncertainty
surrounding the worldwide economy and the political unrest in the Middle East
and Venezuela, which contributed to the higher oil prices.

Natural gas prices also rose during 2002 as inventory storage has
fallen below average historical levels. The decline in natural gas inventory
storage is attributable to reduced North American natural gas production in 2002
and increased demand for natural gas due to winter temperatures that were colder
than the previous year. Although natural gas prices continued to rise during
2002, operators on average have not increased drilling activities. We believe
this is due to the uncertainty surrounding the world economy. The reduced
drilling activity in the U.S. Gulf of Mexico has resulted in continued depressed
utilization rates and dayrates for drilling rigs in that region. Oil companies
continue to work through the effects of industry consolidation, which has
inhibited capital spending on exploration and development. We expect that
further consolidation among our customer base would dampen drilling activity
levels near-term. We cannot predict the future level of demand for our drilling
services or future conditions in the offshore contract drilling industry.

In recent years, we have focused on increasing the number of rigs in
our fleet capable of deepwater offshore drilling. We have incorporated this
focus into our broader, long-standing business strategy to actively expand our
international and offshore deepwater capabilities through acquisitions, rig
upgrades and modifications and to deploy assets in important geological areas.

RESULTS OF OPERATIONS

2002 COMPARED TO 2001

GENERAL

Net income for 2002 was $209,503,000, or $1.57 per diluted share, on
operating revenues of $986,356,000, compared to net income of $262,922,000, or
$1.96 per diluted share, on operating revenues of $1,029,760,000 for 2001.

16

RIG UTILIZATION, OPERATING DAYS AND AVERAGE DAYRATE

The following table sets forth the average rig utilization, operating
days and average dayrate for our offshore fleet for 2002 and 2001:

- ----------

(1) Utilization reflects our policy of reporting on the basis of the number of
actively marketed rigs in our fleet. Percentages reflect the results of
rigs only during the period in which they are owned or operated by us.

(2) "Domestic" encompasses the U.S. Gulf of Mexico.

INTERNATIONAL OPERATIONS

The following table sets forth the operating revenues and gross margin
(operating revenues less direct operating expenses) for our international
operations for 2002 and 2001:

- ----------

(1) For information on the reclassification of reimbursements from customers,
see "Accounting Pronouncements" below.

OPERATING REVENUES. International contract drilling services revenues
increased $124,419,000 due to higher average dayrates in the North Sea, the
Middle East and West Africa and additional operating days in Mexico and the
Middle East. The additional operating days in Mexico were attributable to the
mobilization of four jackup rigs to Mexico from the U.S. Gulf of Mexico for
long-term contracts beginning in the latter part of 2002. International labor
contract drilling services revenues decreased $4,876,000 due to fewer equipment
rentals on the Hibernia Project in Canada and lower utilization on our North Sea
labor contracts. International engineering, consulting and other revenues
decreased $196,000 due to a reduction in equipment fabrication services in the
North Sea, partially offset by an additional engineering services contract in
the North Sea and the expansion of our technology initiative to certain
international markets during 2002.

GROSS MARGIN. International contract drilling services gross margin
increased $65,362,000 due to higher average dayrates in the North Sea, the
Middle East and West Africa and additional operating days in Mexico and the
Middle East. International engineering, consulting and other gross margin
decreased $2,612,000 due to additional operating costs related to the testing
and development of the Well Director(TM) drilling tools acquired in May 2002
and a reduction in equipment fabrication services in the North Sea.

17

DOMESTIC OPERATIONS

The following table sets forth the operating revenues and gross margin
(operating revenues less direct operating expenses) for our domestic operations
for 2002 and 2001:

- ----------

(1) For information on the reclassification of reimbursements from customers,
see "Accounting Pronouncements" below.

OPERATING REVENUES. Domestic contract drilling services revenues
decreased $159,949,000, as soft market conditions in the U.S. Gulf of Mexico
resulted in lower average dayrates and lower utilization. In addition, we moved
four jackup rigs out of the U.S. Gulf of Mexico for long-term contracts in
Mexico during the latter part of 2002. Domestic engineering, consulting and
other revenues increased $137,000 due to a significant project management
engagement by our Triton Engineering ("Triton") subsidiary, partially offset by
fewer of our Noble Engineering & Development Limted ("NED") subsidary's Noble
DrillSmart System(TM) units on third-party rigs.

GROSS MARGIN. Domestic contract drilling services gross margin
decreased $157,757,000 due to lower average dayrates and fewer operating days.
Domestic engineering, consulting and other gross margin decreased $6,410,000 due
to additional research and development expenditures by NED and lower margins on
engineering consulting engagements conducted by Triton.

OTHER ITEMS

DEPRECIATION AND AMORTIZATION EXPENSE. Depreciation and amortization
expense increased $6,579,000 due to various capital upgrades to our rig fleet
and the acquisition in August 2001 of the remaining 50 percent equity interest
in the joint venture that owned the Noble Julie Robertson. As a result of this
acquisition, the results of operations of the Noble Julie Robertson are included
in our Consolidated Statements of Income from the purchase date. Prior to that
date, the investment was accounted for under the equity method.

SELLING, GENERAL AND ADMINISTRATIVE EXPENSES. Selling, general and
administrative ("SG&A") expenses increased $2,642,000 due primarily to
professional fees and filing fees incurred in 2002 related to our corporate
restructuring.

INTEREST EXPENSE. Interest expense decreased $5,130,000 due to lower
average debt balances in 2002.

OTHER, NET. Other, net decreased $991,000 due to recognition of a
realized loss of $9,758,000 in 2002 on an investment in marketable equity
securities resulting from a decline in value considered by management to be
permanent. This loss was partially offset by a gain in 2002 of $5,908,000 on the
sale of a five percent working interest in one of Mariner Energy, Inc.'s
deepwater exploration properties to Pioneer Natural Resources USA, Inc. for
$6,200,000 in cash and the assumption of liabilities related to our share of
drilling and development costs on this property, and $2,638,000 of income from
working interests in other producing deepwater exploration properties. We also
incurred a $400,000 loss on the purchase and retirement of $5,000,000 principal
amount of our 7.50% Senior Notes due 2019 during 2002. In 2001, we reported a
$1,520,000 loss on the purchase and retirement of $43,305,000 principal amount
of our 7.50% Senior Notes. In addition, interest income was lower in 2002 due to
a lower average yield earned on our cash balances and investments in marketable
securities.

18

INCOME TAX PROVISION. Income tax provision decreased $51,728,000 due to
a lower effective tax rate and lower pretax earnings. The effective tax rate was
14 percent in 2002 compared to 25 percent in 2001. The lower effective tax rate
in 2002 was a result of a higher percentage of our pretax earnings being derived
from international operations, which generally have lower effective tax rates
than our domestic operations, and the tax benefits attributable to our corporate
restructuring.

2001 COMPARED TO 2000

GENERAL

Net income for 2001 was $262,922,000, or $1.96 per diluted share, on
operating revenues of $1,029,760,000, compared to net income of $165,554,000, or
$1.22 per diluted share, on operating revenues of $898,224,000 for 2000.

RIG UTILIZATION, OPERATING DAYS AND AVERAGE DAYRATE

The following table sets forth the average rig utilization, operating
days and average dayrate for our offshore fleet for 2001 and 2000:

- ----------

(1) For information on the reclassification of reimbursements from customers,
see "Accounting Pronouncements" below.

OPERATING REVENUES. International contract drilling services revenues
increased $123,298,000 due to higher average dayrates and rig utilization in
West Africa, the North Sea and the Middle East, partially offset by the
expiration of contracts in Venezuela. Labor contract drilling services revenues
increased $1,812,000 due to

19

escalation clauses on our labor contract for the Hibernia Project in Canada,
partially offset by the expiration of a North Sea labor contract. International
engineering, consulting and other revenues increased $5,015,000 due to an
engineering services contract in the North Sea which began during the fourth
quarter of 2000.

GROSS MARGIN. International contract drilling services gross margin
increased $87,545,000 due to higher average dayrates and rig utilization in West
Africa, the North Sea and the Middle East. Labor contract drilling services
gross margin decreased $548,000 due to the expiration of a North Sea labor
contract, partially offset by escalation clauses on our labor contract for the
Hibernia project in Canada. Despite higher revenues, international engineering,
consulting and other gross margin decreased $498,000. This was due to the fact
that we stopped charging management fees to our joint venture that owned the
Noble Julie Robertson once we acquired the entire interest in the joint venture
in the third quarter of 2001.

DOMESTIC OPERATIONS

The following table sets forth the operating revenues and gross margin
(operating revenues less direct operating expenses) for our domestic operations
for 2001 and 2000:

- ----------

(1) For information on the reclassification of reimbursements from customers,
see "Accounting Pronouncements" below.

OPERATING REVENUES. Domestic contract drilling services revenues
increased $67,265,000 due to higher average dayrates and increased operating
days on our jackup rigs. The higher operating statistics on our domestic jackup
rigs reflected improved market conditions in the Gulf of Mexico for most of
2001. There was no turnkey drilling activity in 2001 as Triton revised its
business model during the fourth quarter of 2000 to focus on well site
management, project management and technical services. Domestic engineering,
consulting and other revenues increased $3,854,000 due to additional revenues
from NED and our Maurer Technology Incorporated ("Maurer") subsidiary.

GROSS MARGIN. Domestic contract drilling services gross margin
increased $37,849,000 due to higher average dayrates and increased operating
days on our jackup rigs. There was no turnkey drilling activity in 2001 due to
Triton's revised business model. Domestic engineering, consulting and other
gross margin increased $1,580,000 due to contributions from NED and Maurer.

OTHER ITEMS

DEPRECIATION AND AMORTIZATION EXPENSE. Depreciation and amortization
expense increased $7,788,000 due to various capital upgrades to our rig fleet.

SELLING, GENERAL AND ADMINISTRATIVE EXPENSES. SG&A expenses increased
$514,000 due to higher labor costs.

INTEREST EXPENSE. Interest expense decreased $6,826,000 due to lower
average debt balances in 2001.

20

INCOME TAX PROVISION. Income tax provision increased $24,797,000 due to
higher pretax earnings, partially offset by a lower effective tax rate. The
effective tax rate was 25 percent in 2001 compared to 27 percent in 2000.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Our principal capital resource in 2002 was net cash provided by
operating activities of $445,364,000, which compared to $451,046,000 and
$330,736,000 in 2001 and 2000, respectively. At December 31, 2002, we had cash
and cash equivalents of $192,509,000, $66,130,000 of marketable debt securities
and approximately $48,054,000 of funds available under our bank credit facility.
We had working capital, including cash, of $184,983,000 and $286,500,000 at
December 31, 2002 and 2001, respectively. Total debt as a percentage of total
debt plus shareholders' equity was 25 percent at December 31, 2002 and December
31, 2001.

We repurchased 1,055,000 of our ordinary shares at a total cost of
$33,966,000 during 2002. Additional repurchases, if any, may be made on the open
market or in private transactions at prices determined by us.

During 2002, we sold put options covering an aggregate of 1,300,000 of
our ordinary shares in private transactions at an average price paid to us of
$2.81 per option. Of the 1,300,000 options sold during 2002, 300,000 expired
unexercised and 400,000 were exercised during 2002, which resulted in 600,000
options outstanding at December 31, 2002. All of these options had expired
unexercised as of March 4, 2003. We no longer have any purchase requirement with
regard to any put options previously sold by us.

These share repurchases and sales of put options were effected pursuant
to our share repurchase program covering up to 15,000,000 shares which was
adopted and authorized by the board of directors of Noble. Giving effect to
prior transactions, as of March 6, 2003, 10,249,000 shares remained available
and unreserved under this authorization.

CAPITAL EXPENDITURES

Capital expenditures totaled $268,054,000 and $133,776,000 for 2002 and
2001, respectively. During 2002, we also purchased two semisubmersible drilling
rigs, two baredeck hulls and two jackup drilling rigs for $171,000,000 in the
aggregate, as well as options to purchase two additional jackup rigs for
$24,900,000. In addition, deferred repair and maintenance expenditures totaled
$42,771,000 and $33,507,000 for 2002 and 2001, respectively. We expect that our
capital expenditures and deferred repair and maintenance expenditures for 2003
will aggregate approximately $330,000,000 and $50,000,000, respectively,
including $58,100,000 for the exercise of the options to purchase the two
additional jackup drilling rigs. We had no joint venture fundings in 2002 and
anticipate none in 2003. For information on deferred repair and maintenance
expenditures and joint venture fundings, see Notes 1 and 6 of our accompanying
consolidated financial statements.

In connection with several projects, we have entered into agreements
with various vendors to purchase or construct property and equipment that
generally have long lead times for delivery in connection with several projects.
If we do not proceed with any particular project, we may either seek to cancel
outstanding purchase commitments related to that project or complete the
purchase of the property and equipment. Any equipment purchased for a project on
which we do not proceed would be used, where applicable, as capital spares for
other units in our fleet. If we cancel any of the purchase commitments, the
amounts ultimately paid by us, if any, would be subject to negotiation. As of
December 31, 2002, we had approximately $95,000,000 of outstanding purchase
commitments related to these projects, which are included in the projected 2003
capital expenditure and deferred repair and maintenance amounts above.

Certain projects currently under consideration could require, if they
materialize, capital expenditures or other cash requirements not included in the
2003 budget. In addition, we will continue to evaluate acquisitions of drilling
units from time to time. Factors that could cause actual project capital
expenditures to materially exceed the

21

planned capital expenditures include delays and cost overruns in shipyards,
shortages of equipment, latent damage or deterioration to hull, equipment and
machinery in excess of engineering estimates and assumptions, and changes in
design criteria or specifications during repair or construction.

CREDIT FACILITIES AND LONG-TERM DEBT

Noble Drilling has in place a $200,000,000 bank credit agreement (the
"Credit Agreement"), which extends through May 30, 2006. In connection with our
restructuring, Noble and its wholly-owned subsidiary, Noble Holding (U.S.)
Corporation, have unconditionally guaranteed the performance of Noble Drilling
under the Credit Agreement. As of December 31, 2002, we had outstanding
borrowings and outstanding letters of credit of $125,000,000 and $26,946,000,
respectively, under the Credit Agreement, with $48,054,000 remaining available
thereunder. Additionally, as of December 31, 2002, we had other letters of
credit and third-party corporate guarantees totaling $15,700,000, of which
$3,300,000 is supported by a restricted cash deposit, and $28,383,000 of
performance and customs bonds that had been supported by surety bonds.

At December 31, 2002, our total long-term debt had increased to
$670,139,000, including current maturities of $80,577,000, due to a $125,000,000
borrowing on our bank credit facility during 2002, net of paydowns in 2002 on
other debt of $60,431,000, including the purchase and retirement of $5,000,000
principal amount of our 7.50% Senior Notes due 2019. At December 31, 2002 and
2001, we had no off-balance sheet debt. For additional information on long-term
debt, see Note 7 to our accompanying consolidated financial statements.

We believe that our cash and cash equivalents, net cash provided by
operating activities, available borrowings under lines of credit, and access to
other financing sources will be adequate to meet our anticipated short-term and
long-term liquidity requirements, including capital expenditures and scheduled
debt repayments.

SUMMARY OF OBLIGATIONS AND COMMITMENTS

The following table summarizes our obligations and commitments at
December 31, 2002 (dollar amounts are in thousands):

22

CORPORATE RESTRUCTURING

On April 30, 2002, Noble Corporation, a Cayman Islands company (which
we sometimes refer to in this report as "Noble"), became the successor to Noble
Drilling Corporation, a Delaware corporation (which we sometimes refer to as
"Noble Drilling"), as part of the internal corporate restructuring of Noble
Drilling and its subsidiaries. This restructuring was approved by the
stockholders of Noble Drilling at its 2002 annual stockholders meeting. The
proposal to adopt the restructuring passed with 106,694,424 shares voted in
favor of the proposal (representing 96.4 percent of the shares voted on the
proposal). The restructuring was accomplished through the merger of an indirect,
wholly-owned subsidiary of Noble Drilling with and into Noble Drilling. Noble
Drilling survived the merger and is now an indirect, wholly-owned subsidiary of
Noble. In addition, as a result of the merger, all of the outstanding shares of
common stock (and the related preferred stock purchase rights) of Noble Drilling
were exchanged for ordinary shares (and related preferred share purchase rights)
of Noble. Noble and its subsidiaries, including Noble Drilling, continue to
conduct the businesses previously conducted by the Noble Drilling corporate
group prior to the merger. We accounted for the restructuring as a
reorganization of entities under common control. Consequently, the consolidated
amounts of assets, liabilities and shareholders' equity did not change as a
result of the restructuring.

Noble Drilling sought stockholder approval of and effected the
restructuring as a means to remain competitive in the global marketplace to
provide diversified services to the oil and gas industry. Under the restructured
organization, we gain flexibility to reduce our worldwide corporate effective
tax rate, increase the operational efficiencies of our business, and create a
corporate structure that is generally more favorable for expansion of our
business. Additionally, we believe Noble could be a more attractive investment
alternative to a wider range of investors.

For the year ended December 31, 2002, 65 percent of our revenues and 86
percent of our net income was derived from drilling operations outside of the
United States. Our restructuring was in part driven by inequitable treatment
under current U.S. tax laws, which impose taxes on the worldwide income of U.S.
companies. This method of taxation places U.S.-based multinationals at a
competitive disadvantage. The parent companies of certain of our competitors,
including our two largest competitors, are incorporated in the Cayman Islands
and other non-U.S. countries that impose either no tax or tax at rates
substantially less than the United States.

As previously disclosed and widely reported in the media, during the
107th Congress several bills had been introduced in the U.S. House of
Representatives and the U.S. Senate which dealt with various aspects of
corporate "inversions". Although previously proposed legislation, if enacted in
its form as originally filed, would have substantially reduced or eliminated the
benefits of the restructuring to Noble, other proposed legislation would have
allowed Noble to maintain the benefits of the restructuring. Proposed
legislation was also directed towards leveling the playing field with respect to
provisions in the U.S. Internal Revenue Code that put U.S. companies competing
in a global marketplace at a competitive disadvantage.

Legislation similar to bills proposed in 2002 has been, or likely will
be, introduced in the 108th Congress. Our consolidated financial statements for
the year ended December 31, 2002 include a reduction in the income tax provision
of $9,000,000 for tax benefits attributable to this restructuring.

CRITICAL ACCOUNTING POLICIES

Our consolidated financial statements are impacted by the accounting
policies used and the estimates and assumptions made by management during their
preparation. Critical accounting policies and estimates that most impact our
consolidated financial statements are those that relate to our property and
equipment, insurance retention, revenue recognition and income taxes.

Property and equipment is stated at cost, reduced by provisions to
recognize economic impairment in value when management determines that such
impairment has occurred. Major replacements and improvements are capitalized.
When assets are sold, retired or otherwise disposed of, the cost and related
accumulated depreciation are eliminated from the accounts and the gain or loss
is recognized. Repair and maintenance costs are generally charged to expense as
incurred; however, overhauls related to large-scale maintenance projects are
deferred when

23

incurred and amortized into contract drilling expense over a 36-month period.
Drilling equipment and facilities are depreciated using the straight-line method
over the estimated useful lives as of the in-service date or date of major
refurbishment. Estimated useful lives of our drilling equipment range from three
to twenty-five years. Other property and equipment is depreciated using the
straight-line method over useful lives ranging from two to twenty years.

We evaluate the realization of our long-lived assets, including
property and equipment, whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. An impairment loss
exists when estimated undiscounted cash flows expected to result from the use of
the asset and its eventual disposition are less than its carrying amount. Any
impairment loss recognized represents the excess of the asset's carrying value
as compared to its estimated fair value. Prior to an impairment loss being
recognized, an independent appraisal would be performed to determine the asset's
estimated fair value. No impairment losses were recorded on our property and
equipment balances during the years ended December 31, 2002, 2001 and 2000.
However, on March 31, 2002, we recognized an impairment loss of $9,758,000 on an
investment in equity securities resulting from a decline in value considered by
management to be permanent. There were no other impairment losses during the
years ended December 31, 2002, 2001 and 2000.

We maintain insurance coverage against certain marine liabilities,
including liability for physical damage to our drilling rigs and personal injury
to our drilling crews. Our marine package policy insures us for physical damage
to our drilling rigs up to the fair value of each rig. During 2002, we retained
the first $1,000,000 per occurrence under this policy and continued to retain a
portion of each loss in excess of $1,000,000 to a maximum of $10,000,000. If a
claim exceeded $10,000,000, the amount in excess of $10,000,000 was fully
covered. Our protection and indemnity policy, which insures us for personal
injury to our drilling crews, had a standard deductible of $100,000 per
occurrence. In addition, we retained $7,250,000 of claims in the aggregate
beyond the standard deductible. We accrue for these deductibles during the year
and the insurance retention reserve is adjusted based on actual claims losses.
Our marine package also included loss of hire coverage for certain high-dayrate
rigs. Under this policy, we did not recover any lost revenue until the rig was
off-rate beyond 21 days due to an insured physical damage claim. We did not
accrue for such losses. Instead, these losses were recorded as revenue was lost.

Due to significant losses suffered by the insurance industry in the
past several years, the offshore drilling industry is facing significant
increases in premium and retention levels. Based on an evaluation of our claims
history, increased pricing in the insurance market and our ability to accept a
higher retention level, we have raised our retention level on our marine package
policy to $10,000,000 per occurrence in 2003. The retention level on our
protection and indemnity policy remains unchanged in 2003.

Revenues generated from our dayrate-basis drilling contracts, labor
contracts, and engineering services and project management engagements are
recognized as services are performed. We may receive lump-sum fees for the
mobilization of equipment and personnel. The net of mobilization fees received
and costs incurred to mobilize an offshore rig from one market to another is
recognized over the term of the related drilling contract. Costs incurred to
relocate drilling units to more promising geographic areas in which a contract
has not been secured are expensed as incurred. Lump-sum payments received from
customers relating to specific contracts are deferred and amortized to income
over the term of the drilling contract.

During 2002, we adopted Emerging Issues Task Force No. 01-14, Income
Statement Characterization of Reimbursements Received for Out-of-Pocket Expenses
Incurred ("EITF 01-14"). Pursuant to EITF 01-14, we record reimbursements from
customers for "out-of-pocket" expenses as revenue and the related cost as direct
costs. See "Accounting Pronouncements" below for additional information.

Noble is a Cayman Islands company. The Cayman Islands does not impose
corporate income taxes. Consequently, income taxes have been provided based on
the laws and rates in effect in the countries in which operations are conducted,
or in which Noble and/or its subsidiaries are considered resident for income tax
purposes. Applicable U.S. and foreign income and withholding taxes have not been
provided on undistributed earnings of Noble's subsidiaries. We do not intend to
repatriate such undistributed earnings for the foreseeable future except for
distributions upon which incremental income and withholding taxes would not be
material. In certain circumstances, we expect that, due to changing demands of
the offshore drilling markets and the ability to redeploy our offshore drilling
units, certain of such units will not reside in a location long enough to give
rise to future tax

24

consequences. As a result, no deferred tax liability has been recognized in
these circumstances. Should our expectations change regarding the length of time
an offshore drilling unit will be used in a given location, we will adjust
deferred taxes accordingly.

For additional information on our accounting policies, see Note 1 to
our accompanying consolidated financial statements.

ACCOUNTING PRONOUNCEMENTS

In July 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 141, Business
Combinations ("SFAS 141"), and SFAS No. 142, Goodwill and Other Intangible
Assets ("SFAS 142"). SFAS 141 requires that all business combinations initiated
after June 30, 2001 be accounted for using the purchase method of accounting. As
we had no business combinations in process upon this statement becoming
effective, adoption of SFAS 141 did not have an impact on our consolidated
results of operations, cash flows or financial position. SFAS 142 requires that
goodwill and other intangible assets no longer be amortized, but rather tested
for impairment at least annually. SFAS 142 is effective for fiscal years
beginning after December 15, 2001. In conjunction with the adoption of SFAS 142
on January 1, 2002, we completed the initial transition impairment test required
by SFAS 142, as well as our annual impairment test as of December 31, 2002, and
determined that our existing goodwill was not impaired. Our adoption of SFAS 142
did not have a material impact on our consolidated results of operations, cash
flows or financial position.

In October 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets ("SFAS 144"). SFAS 144 supersedes
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of ("SFAS 121") and the accounting and
reporting provisions of Accounting Principles Board Opinion No. 30, Reporting
the Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions ("APB 30"), for the disposal of a segment of a business (as defined
in that Opinion). SFAS 144 retains the fundamental provisions of SFAS 121
concerning the recognition and measurement of the impairment of long-lived
assets to be held and used and the measurement of long-lived assets to be
disposed of by sale but provides additional guidance with regard to discontinued
operations and assets to be disposed of. Furthermore, SFAS 144 excludes goodwill
from its scope and, therefore, eliminates the requirement under SFAS 121 to
allocate goodwill to long-lived assets to be tested for impairment. SFAS 144 is
effective for fiscal years beginning after December 15, 2001. Our adoption of
SFAS 144 on January 1, 2002 did not have a material impact on our consolidated
results of operations, cash flows or financial position.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections ("SFAS 145"). SFAS 145 rescinds FASB Statement No. 4, Reporting
Gains and Losses from Extinguishment of Debt, and an amendment of that
statement, FASB Statement No. 64, Extinguishments of Debt Made to Satisfy
Sinking-Fund Requirements. SFAS 145 also rescinds FASB Statement No. 44,
Accounting for Intangible Assets of Motor Carriers and amends FASB Statement No.
13, Accounting for Leases, to eliminate an inconsistency between the required
accounting for sale-leaseback transactions and the required accounting for
certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. SFAS 145 also amends other existing authoritative
pronouncements to make various technical corrections, clarify meanings, or
describe their applicability under changed conditions. Under FASB Statement No.
4, all gains and losses from the extinguishment of debt were required to be
aggregated and, if material, classified as an extraordinary item, net of related
income taxes. Under SFAS 145, gains and losses from the extinguishment of debt
should be classified as extraordinary items only if they meet the criteria of
APB 30. APB 30 distinguishes the transactions that are part of an entity's
recurring operations from those that are unusual or infrequent or that meet the
criteria for classification as an extraordinary item. The provisions of SFAS 145
related to the rescission of FASB Statement No. 4 are effective for fiscal years
beginning after May 15, 2002. The remaining provisions of SFAS 145 are effective
for all financial statements issued after May 15, 2002. During 2002, we elected
to adopt early the provisions of SFAS 145. Pursuant to our early adoption, we
have included a $400,000 loss on the purchase and retirement of $5,000,000
principal amount of our 7.50% Senior Notes due 2019 during 2002 in income before
income taxes in our Consolidated Statements of Income for the year ended
December 31, 2002. In addition, we reclassified the extraordinary charge of
$1,520,000 (before tax effect of $532,000), related to the

25

purchase and retirement of $43,305,000 principal amount of our 7.50% Senior
Notes during 2001 to income before income taxes in our Consolidated Statements
of Income for the year ended December 31, 2001.

In November 2002, the FASB issued Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others ("FIN 45"). FIN 45 expands existing
accounting guidance and disclosures to be made by a guarantor in its interim and
annual financial statements about its obligations under certain guarantees that
it has issued. FIN 45 also clarifies that a guarantor is required to recognize,
at the inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee. The disclosure requirements of
FIN 45 are effective for financial statements ending after December 15, 2002.
The remaining provisions of FIN 45 are effective for guarantees issued or
modified after December 31, 2002. We do not expect the adoption of FIN 45 to
have a material impact on our consolidated results of operations, cash flows or
financial position.

In December 2002, the FASB issued SFAS No. 148, Accounting for
Stock-Based Compensation--Transition and Disclosure ("SFAS 148"). SFAS 148
amends SFAS No. 123, Accounting for Stock-Based Compensation ("SFAS 123"), to
provide alternative methods of transition to the fair value method of accounting
for stock-based employee compensation. In addition, SFAS 148 amends the
disclosure provisions of SFAS 123 to require disclosure in the summary of
significant accounting policies of the effects of an entity's accounting policy
with respect to stock-based employee compensation on reported net income and
earnings per share in annual and interim financial statements. SFAS 148 does not
amend SFAS 123 to require companies to account for their employee stock-based
awards using the fair value method. However, the disclosure provisions are
required for all companies with stock-based employee compensation, regardless of
whether they utilize the fair value method of accounting described in SFAS 123
or the intrinsic value method described in APB Opinion No. 25, Accounting for
Stock Issued to Employees. SFAS 148's amendment of the transition and annual
disclosure provisions of SFAS 123 are effective for fiscal years ending after
December 15, 2002. We have adopted the annual disclosure provisions of SFAS 123.
We do not believe that the adoption of this standard will have a material impact
on our consolidated results of operations, cash flows or financial position.

During 2002, we adopted EITF 01-14. EITF 01-14 requires that
"out-of