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================================================================================

                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   ----------

                                    FORM 10-K
                                  ANNUAL REPORT
     Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
                        COMMISSION FILE NUMBER: 000-49887

                                   ----------

                             NABORS INDUSTRIES LTD.

                             INCORPORATED IN BERMUDA
                     2ND FLOOR, INTERNATIONAL TRADING CENTRE
                                     WARRENS
                                  P.O. BOX 905E
                              ST. MICHAEL, BARBADOS
                                 (246) 421-9471

                                   98-0363970
                      (I.R.S. Employer Identification No.)

                                   ----------

                SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE
                        SECURITIES EXCHANGE ACT OF 1934:

                                                         NAME OF EACH
         TITLE OF EACH CLASS                      EXCHANGE ON WHICH REGISTERED
         -------------------                      ----------------------------
Common Shares, $.001 par value per share        The American Stock Exchange, LLC

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 Exchange Act Rule 12b-2).

                               YES [X]   NO [ ]

The aggregate market value of the 130,963,344 common shares held by
non-affiliates of the registrant, based upon the closing price of our common
shares as of the last business day of our most recently completed second fiscal
quarter, June 30, 2003, of $39.53 per share as reported on the American Stock
Exchange, was $5,176,980,988. Common Shares held by each officer and director
and by each person who owns 5% or more of the outstanding common shares have
been excluded in that such persons may be deemed affiliates. This determination
of affiliate status is not necessarily a conclusive determination for other
purposes.

The number of common shares, par value $.001 per share, outstanding as of
February 29, 2004 was 148,047,219. In addition, our subsidiary, Nabors
Exchangeco (Canada) Inc., had 372,108 exchangeable shares outstanding as of
February 29, 2004 that are exchangeable for Nabors common shares on a
one-for-one basis, and have essentially identical rights as Nabors Industries
Ltd. common shares; including but not limited to voting rights and the right to
receive dividends, if any.

                       DOCUMENTS INCORPORATED BY REFERENCE
                        (TO THE EXTENT INDICATED HEREIN)

Specified portions of the 2003 Annual Report to Shareholders (Parts I, II and
IV) Specified portions of the 2004 Notice of Annual Meeting of Shareholders and
Proxy Statement (Part III)

================================================================================



<PAGE>


                             NABORS INDUSTRIES LTD.
                             FORM 10-K ANNUAL REPORT
                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

                                TABLE OF CONTENTS

<Table>
<S>                                                                                                              <C>
PART I
Item 1.           Business                                                                                        1
                  I.       Introduction                                                                           1
                  II.      Description of Business                                                                2
                           A.       Our Fleet of Rigs                                                             2
                           B.       Types of Drilling Contracts                                                   4
                           C.       Well Servicing and Workover Services                                          5
                           D.       Oil and Gas Investments                                                       6
                           E.       Other Services                                                                6
                           F.       Our Employees                                                                 7
                           G.       Seasonality                                                                   8
                           H.       Research and Development                                                      8
                  III.     Customers; Markets; Industry Conditions and Trends                                     8
                           A.       Contract Drilling                                                             8
                           B.       Oil and Gas Segment                                                           9
                           C.       Other Operating Segments                                                     10
                           D.       Industry Conditions                                                          10
                           E.       Competitive Conditions                                                       11
                  IV.      Recent Developments                                                                   12
                           A.       Operating Results                                                            12
                           B.       Debt Offering and Debt Redemptions                                           12
                           C.       Oil and Gas Investments                                                      13
                  V.       Our Business Strategy                                                                 13
                  VI.      Risk Factors                                                                          14
                  VII.     Acquisitions and Divestitures                                                         19
                  VIII.    Environmental Compliance                                                              21
                  IX.      Available Information                                                                 21
Item 2.           Properties                                                                                     21
Item 3.           Legal Proceedings                                                                              22
Item 4.           Submission of Matters to a Vote of Security Holders                                            22

PART II
Item 5.           Market for Registrant's Common Equity and Related Stockholder Matters                          22
                  I.       Market and Stock Prices                                                               22
                  II.      Dividend Policy                                                                       27
                  III.     Shareholder Matters                                                                   27
Item 6.           Selected Financial Data                                                                        27
Item 7.           Management's Discussion and Analysis of Financial Condition and Results of
                  Operations                                                                                     27
Item 7A.          Quantitative and Qualitative Disclosures About Market Risk                                     27
Item 8.           Financial Statements and Supplementary Data                                                    27
Item 9.           Changes in and Disagreements With Accountants on Accounting and Financial
                  Disclosure                                                                                     27
Item 9A.          Controls and Procedures                                                                        27

PART III
Item 10.          Directors and Executive Officers of the Registrant                                             28
Item 11.          Executive Compensation                                                                         28
Item 12.          Security Ownership of Certain Beneficial Owners and Management and Related
                  Shareholder Matters                                                                            28
Item 13.          Certain Relationships and Related Transactions                                                 28
Item 14           Principal Accountant Fees and Services                                                         29

PART IV
Item 15.          Exhibits, Financial Statement Schedules and Reports on Form 8-K                                29
</Table>



                                       i
<PAGE>


                           FORWARD-LOOKING STATEMENTS


We often discuss expectations regarding our future markets, demand for our
products and services, and our performance in our annual and quarterly reports,
press releases, and other written and oral statements. Statements that relate to
matters that are not historical facts are "forward-looking statements" within
the meaning of the safe harbor provisions of Section 27A of the Securities Act
of 1933 and Section 21E of the Securities Exchange Act of 1934. These
"forward-looking statements" are based on an analysis of currently available
competitive, financial and economic data and our operating plans. They are
inherently uncertain and investors should recognize that events and actual
results could turn out to be significantly different from our expectations. By
way of illustration, when used in this document, words such as "anticipate,"
"believe," "expect," "plan," "intend," "estimate," "project," "will," "should,"
"could," "may," "predict" and similar expressions are intended to identify
forward-looking statements.

You should consider the following key factors when evaluating these
forward-looking statements:

     o    fluctuations in worldwide prices of and demand for natural gas and
          oil;

     o    fluctuations in levels of natural gas and oil exploration and
          development activities;

     o    fluctuations in the demand for our services;

     o    the existence of competitors, technological changes and developments
          in the oilfield services industry;

     o    the existence of operating risks inherent in the oilfield services
          industry;

     o    the existence of regulatory and legislative uncertainties;

     o    the possibility of changes in tax laws;

     o    the possibility of political instability, war or acts of terrorism in
          any of the countries in which we do business; and

     o    general economic conditions.

Our businesses depend, to a large degree, on the level of spending by oil and
gas companies for exploration, development and production activities. Therefore,
a sustained increase or decrease in the price of natural gas or oil, which could
have a material impact on exploration, development and production activities,
could also materially affect our financial position, results of operations and
cash flows.

The above description of risks and uncertainties is by no means all-inclusive,
but is designed to highlight what we believe are important factors to consider.
For a more detailed description of risk factors, please see "Part I - Item 1 -
BUSINESS - RISK FACTORS".

Unless the context requires otherwise, references in this Annual Report on Form
10-K to "we," "us," "our", or "Nabors" means Nabors Industries Ltd. and, where
the context requires, includes our subsidiaries.

                                     PART I

Please see the Glossary of Drilling Terms included as Annex A to this document
for a brief explanation of drilling terms used throughout this document.

ITEM 1.  BUSINESS

I.       INTRODUCTION.

Nabors is the largest land drilling contractor in the world, with almost 600
land drilling rigs. We conduct oil, gas and geothermal land drilling operations
in the U.S. Lower 48 states, Alaska, Canada, South and Central America, the
Middle East, the Far East, and Africa. We are also one of the largest land
well-servicing and workover contractors in the United States and Canada. We own
approximately 750 land workover and well-servicing rigs in the United States,
primarily in the southwestern and western United States, and approximately 200
land workover and well-servicing rigs in Canada. Nabors is a leading provider of
offshore platform workover and drilling rigs, and owns 45 platform, 16 jack-up
and three barge rigs in the Gulf of Mexico and international markets. These rigs



                                       1
<PAGE>


provide well-servicing, workover and drilling services. We also have a 50%
ownership interest in a joint venture in Saudi Arabia, which owns 17 rigs.

To further supplement and complement our primary business, we offer a wide range
of ancillary well-site services, including engineering, transportation,
construction, maintenance, well logging, directional drilling, rig
instrumentation, data collection and other support services in selected domestic
and international markets. Our land transportation and hauling fleet includes
approximately 240 rig and oilfield equipment hauling tractor-trailers and a
number of cranes, loaders and light-duty vehicles. We maintain approximately 300
fluid hauling trucks, approximately 800 fluid storage tanks, ten salt water
disposal wells and other auxiliary equipment used in drilling, workover and
well-servicing operations in the United States. In addition, we time charter a
fleet of 31 marine transportation and supply vessels, which provide
transportation of drilling materials, supplies and crews for offshore operations
primarily in the Gulf of Mexico. We manufacture and lease or sell top drives for
a broad range of drilling applications, directional drilling systems, rig
instrumentation and data collection equipment, and rig reporting software. We
have also made selective investments in oil and gas exploration, development and
production activities, most recently with El Paso Corporation.

The majority of our business is conducted through our various Contract Drilling
operating segments, which include our drilling, workover and well-servicing
operations, on land and offshore. Our operating segments engaged in marine
transportation and supply services, drilling technology and top drive
manufacturing, directional drilling, rig instrumentation and software, and
construction and logistics operations are aggregated in a category labeled Other
Operating Segments for segment reporting purposes. Our limited oil and gas
exploration, development and production operations are included in a category
labeled Oil and Gas for segment reporting purposes.

Nabors was formed as a Bermuda-exempt company on December 11, 2001. Through
predecessors and acquired entities, Nabors has been continuously operating in
the drilling sector since the early 1900s. Our principal executive offices are
located at 2nd Fl. International Trading Centre, Warrens, St. Michael, Barbados.
Our phone number at our principal executive offices is (246) 421-9471.


II.      DESCRIPTION OF BUSINESS.

         A.       OUR FLEET OF RIGS.

Our rigs include land-based rigs and offshore platform, jack-up and barge rigs.
Drilling rigs come in a wide variety of sizes and capabilities, and may include
specialized equipment, such as top drives, or have design features or
modifications for specialized drilling conditions, such as arctic drilling. The
rigs are classified by their depth capabilities and by whether their power
systems are mechanical or electric. They generally are powered by two to four
large diesel engines. An electric rig differs from a mechanical rig in that it
converts the diesel power into electricity to power the rig. This gives the rig
operator the ability to deliver the same amount of torque at high and low
speeds, permitting more finite control of the primary rig components, including
the drawworks and mud pumps. We believe this electric capability enhances
operating efficiency and safety, reduces drilling time and saves the customer
money, particularly in deeper applications. Because of these advantages, diesel
electric rigs, known in the industry as silicon-controlled rectifier or SCR
rigs, generally are preferred by our customers, and often enjoy higher
utilization and dayrates than similarly sized mechanical rigs.

Nabors' various types of rigs perform drilling, workover (major overhaul or
remediation of an existing wellbore and/or plugging and redrilling the well) and
well-servicing (routine repair and maintenance of mechanical problems). A
drilling rig can perform drilling, workover and well-servicing services,
depending on its configuration. However, primarily due to cost and size
considerations, a land drilling rig is rarely used for well-servicing or
workover applications. Instead, smaller, mobile well-servicing and workover rigs
are used. Offshore, a drilling rig is occasionally used for workover and
well-servicing applications, particularly if it is on location, because it is
more cost-effective to use a rig in place rather than transporting an
alternative, special purpose rig to an offshore location. Each rig is rated for
operations up to a range of depth depending upon well design (straight vs.
directional; bore and pipe sizes and weights). The basic types of rigs operated
by Nabors are described below.



                                       2
<PAGE>


o    Land Rigs. A land-based drilling rig generally consists of engines, a
     drawworks (which hoists and lowers the drill string in and out of the
     well), a mast (or derrick), pumps to circulate the drilling fluid (mud)
     under various pressures, blowout preventers, drill string and related
     equipment. The engines power the different pieces of equipment, including a
     rotary table or top drive that turns the drill string, causing the drill
     bit to bore through the subsurface rock layers. Rock cuttings are carried
     to the surface by the circulating drilling fluid. The intended well depth,
     bore hole diameter and drilling site conditions are the principal factors
     that determine the size and type of rig most suitable for a particular
     drilling job. A land-based workover or well-servicing rig consists of a
     mobile carrier, engine, drawworks and a mast. The primary function of a
     workover or well-servicing rig is to act as a hoist so that pipe, sucker
     rods and down-hole equipment can be run into and out of a well. Typically,
     land-based drilling, workover and well-servicing rigs can be readily moved
     between well sites and between geographic areas of operations by using our
     fleet of cranes, loaders and transport vehicles.

o    Platform Rigs. Platform rigs provide offshore workover, drilling and
     re-entry services. Our platform rigs have drilling and/or well-servicing or
     workover equipment and machinery arranged in modular packages that are
     transported to, and assembled and installed on, fixed offshore platforms
     owned by the customer. Fixed offshore platforms are steel tower-like
     structures that either stand on the ocean floor or are moored floating
     structures. The top portion, or platform, sits above the water level and
     provides the foundation upon which the platform rig is placed. Our fleet of
     platform rigs includes:

     o    Minimum space, modular platform workover rigs with engines rated 750
          horsepower or below, which include the 500 horsepower Sundowner(R)
          series. These platform workover rigs are self-elevating (that is, they
          can be off-loaded with the platform crane, rather than requiring a
          separate barge and crane to assemble), and are designed to fit the
          geometry of nearly any producing platform without major modifications
          to either the rig or the platform.

     o    Minimum space, modular platform workover and re-drilling rigs with
          engines rated at horsepowers greater than 750, which include the 1000
          horsepower Super Sundowner(R) rigs. These rigs, which are enhanced
          versions of the modular platform workover rigs, have more powerful mud
          pump systems and greater hook load capacities. This enables the rigs
          to be used in more rigorous workover, re-entry, side-tracking or
          horizontal drilling operations.

     o    Minimum Area, Self-Elevating, or MASE(R), drilling rigs are our higher
          horsepower modular platform rigs. They represent a smaller and
          lighter, full-scale drilling rig patterned after the Super
          Sundowner(R) but have horsepower ranging from 1500 hp to 3000 hp.

     o    Modular Offshore Dynamic Series (MODS) platform rigs ranging from 1000
          hp to 1500 hp are our newest addition to the modular rig fleet. They
          have been reengineered to be lighter weight, and dynamically capable
          to meet motion criteria of deepwater SPAR and TLP platforms.

     o    API (American Petroleum Institute)-style drilling rigs have similar
          capabilities to the MASE(R) rigs, but generally come in larger
          modules. Unlike our other platform rigs, API-style rigs are not
          self-elevating, and require a separate barge crane to load onto, and
          off of, the platform.

     We also own several land rigs modified for offshore work for drilling on
     mudslide and selected conventional offshore platforms. These rigs generally
     are self-elevating and modular.

o    Jack-up Rigs. Jack-up rigs are mobile, self-elevating drilling and workover
     platforms equipped with legs that can be lowered to the ocean floor until a
     foundation is established to support the hull, which contains the drilling
     and/or workover equipment, jacking system, crew quarters, loading and
     unloading facilities, storage areas for bulk and liquid materials,
     helicopter landing deck and other related equipment. The rig legs may
     operate independently or have a mat attached to the lower portion of the
     legs in order to provide a more stable foundation in soft bottom areas.
     Independent leg rigs are better suited for harsher or uneven seabed
     conditions and drilling locations where subsea pipelines are present. Many
     of our jack-up rigs are of cantilever design -- a feature that permits the
     drilling platform to be extended out from the hull, allowing it to perform
     drilling or



                                       3
<PAGE>


     workover operations over adjacent, fixed platforms. Nabors' shallow
     workover jack-up rigs generally are subject to a maximum water depth of
     approximately 125 feet, while some of our jack-up rigs may drill in water
     depths as shallow as 13 feet. Nabors also has deeper water depth capacity
     jack-up rigs that are capable of drilling at depths between 8 feet and 150
     to 250 feet. The water depth limit of a particular rig is determined by the
     length of the rig's legs and the operating environment. Moving a rig from
     one drill site to another involves lowering the hull down into the water
     until it is afloat and then jacking up its legs with the hull floating. The
     rig is then towed to the new drilling site.

o    Inland Barge Rigs. One of Nabors' barge rigs is a full-size drilling unit.
     Nabors also owns two workover inland barge rigs. These barges are designed
     to perform plugging and abandonment, well service or workover services in
     shallow inland, coastal or offshore waters. Our barge rigs can operate at
     depths between three and twenty feet.

Additional information on the number and location of our rigs can be found below
under the caption "Business - Customers; Market; Industry Conditions and
Trends".

         B.       TYPES OF DRILLING CONTRACTS.

Our rigs are employed under individual contracts which extend either over a
stated period of time or the time required to drill a well or a stated number of
wells to a specified depth. On land in the U.S. Lower 48 states and Canada, we
typically contract on a single-well basis, with extensions subject to mutual
agreement on pricing and other significant terms. Contracts relating to offshore
drilling and land drilling in Alaska and international markets generally provide
for longer terms, usually from one to five years. Offshore workover projects are
often on a single-well basis. We generally are awarded drilling contracts
through competitive bidding, although we occasionally enter into contracts by
direct negotiation. Most of our single-well contracts are subject to termination
by the customer on short notice, but some can be firm for a number of wells or a
period of time, and may provide for early termination compensation in certain
circumstances. The contract terms and rates may differ depending on a variety of
factors, including competitive conditions, the geographical area, the geological
formation to be drilled, the equipment and services to be supplied, the on-site
drilling conditions and the anticipated duration of the work to be performed.

Drilling contracts provide for compensation on a daywork, footage or turnkey
basis. In each case, we provide the rig and crews. The principal differences
among the types of contracts are set forth below.

o    Daywork Contracts. A daywork contract generally provides for a basic rate
     per day when drilling (the dayrate) and for lower rates when the rig is
     moving, or when drilling operations are interrupted or restricted by
     equipment breakdowns, actions of the customer or adverse weather conditions
     or other conditions beyond our control. In addition, daywork contracts may
     provide for a lump sum fee for the mobilization and demobilization of the
     rig, which in most cases approximates our incurred costs.

o    Footage Contracts. Under footage contracts, a drilling contractor typically
     runs casing and provides drill bits. We receive payment on the basis of a
     rate per foot drilled. The customer continues to provide drilling mud,
     casing, cementing and well design expertise. If we drill the well in less
     time than was estimated, then we have the opportunity to improve our
     margins over those that would be attainable under a daywork contract to the
     same depth. If, however, we take longer to drill the well than we
     estimated, our margins will be lower. In footage contracts, a drilling
     contractor bears the cost of the services and supplies until the well has
     been drilled to the agreed depth. Such contracts therefore require the
     drilling contractor to make significant up-front working capital
     commitments prior to receiving payment. Footage contracts generally contain
     greater risks for a contractor such as Nabors than daywork contracts, but
     fewer risks than turnkey contracts. Under footage contracts, the contractor
     assumes certain risks associated with loss of hole from fire, blowout and
     other drilling risks. However, footage contracts generally protect the
     contractor from such risks when unexpected drilling conditions such as
     abnormal pressure, impenetrable geologic formation or loss circulation
     zones are present.

o    Turnkey Contracts. In turnkey contracts, the drilling contractor drills a
     well to a specified depth for a fixed price regardless of the time required
     or the problems encountered in drilling the well. On a turnkey well, the



                                       4
<PAGE>


     drilling contractor provides technical expertise and engineering services,
     as well as most of the equipment required to complete the well, and is
     compensated only when the agreed scope of work has been satisfied. In
     turnkey contracts, the drilling contractor bears the cost of performing the
     drilling services until the well has been drilled, and accordingly, such
     contracts require the drilling contractor to make significant working
     capital commitments. If the well is not completed to the specified depth,
     we may not receive the turnkey price. Turnkey contracts generally involve a
     higher degree of risk than daywork and footage contracts because the
     drilling contractor assumes greater risks (including risk of blowout, loss
     of hole, stuck drill pipe, machinery breakdowns, abnormal drilling
     conditions and risks associated with subcontractors' services, supplies,
     cost escalation and personnel) and bears the cost of unanticipated downhole
     problems and price escalation. Generally, however, our agreements limit
     catastrophic risks associated with blowout, redrill and pollution to a
     specific sum. The customer assumes the risk of losses in excess of the
     agreed level. If the well is successfully drilled without undue delay or
     complication, our margins under these types of contracts are usually
     greater than under daywork and footage contracts.

During 2003 substantially all of our drilling contracts were on a daywork basis.
Our preferred strategy is to operate drilling rigs under daywork contracts.
However, we continually analyze market conditions, customer requirements, rig
demand and the experience of our personnel to determine how to contract our
fleet most profitably. In addition, we may seek alternative accommodations with
certain customers as a means of ensuring long-term drilling commitments and
healthy customer relations, including, potentially, entering into footage or
turnkey contracts on occasion or accepting less favorable contractual terms
involving allocation of risk. Because of this, there can be no assurance that we
will not suffer a loss that is not insured as a result of entering into such
higher risk contracts, and any such uninsured loss could have a material adverse
effect on our financial position, cash flows and results of operations.

         C.       WELL SERVICING AND WORKOVER SERVICES.

Although some wells in the United States flow oil to the surface without
mechanical assistance, most are in mature production areas that require pumping
or some other form of artificial lift. Pumping oil wells characteristically
require more maintenance than flowing wells because of the operation of the
mechanical pumping equipment installed. The extent and type of well-servicing
and workover services we provide on producing wells is dependent upon many
variables. The following is a summary of our well-servicing and workover
services.

o    Well-Servicing/Maintenance Services. We provide maintenance services on the
     mechanical apparatus used to pump or lift oil from producing wells. These
     services include, among other things, repairing and replacing pumps, sucker
     rods and tubing. We provide the rigs, equipment and crews for these tasks,
     which are performed on both oil and natural gas wells, but which are more
     commonly required on oil wells. Well-servicing rigs have the same basic
     components as drilling rigs (that is, a derrick, a drawworks and an
     engine). Many of these rigs also have pumps and tanks that can be used for
     circulating fluids into and out of the well. Maintenance services typically
     take less than 48 hours to complete. Well-servicing rigs generally are
     provided to customers on a call-out basis. We are paid an hourly rate and
     work typically is performed five days a week during daylight hours.

o    Workover Services. In addition to needing periodic maintenance, producing
     oil and natural gas wells occasionally require major repairs or
     modifications, called "workovers." Workovers may be needed, for example, to
     remedy equipment failures, plug back the bottom of a well to reduce the
     amount of water being produced with the oil and natural gas, clean out and
     re-complete a well if production has declined, repair leaks, or convert a
     producing well to an injection well for secondary or enhanced recovery
     projects. These extensive workover operations normally are carried out with
     a well-servicing rig that includes additional specialized accessory
     equipment, which may include rotary drilling equipment, mud pumps, mud
     tanks and blowout preventers, depending upon the particular type of
     workover operation. Most of Nabors' larger well-servicing rigs are designed
     and can be equipped to handle the more complex workover operations. A
     workover may last anywhere from a few days to several weeks.

o    Completion Services. The kinds of activities necessary to carry out a
     workover operation are essentially the same as those that are required to
     "complete" a well when it is first drilled. The completion process may
     involve selectively perforating the well casing at the depth of discrete
     producing zones, stimulating and testing



                                       5
<PAGE>


     these zones and installing down-hole equipment. Oil and gas production
     companies often find it more efficient to move a larger and more expensive
     drilling rig off location after an oil or natural gas well has been drilled
     and to move in a specialized well-servicing rig to perform completion
     operations. Our rigs often are used for this purpose. The completion
     process may take a few days to several weeks.

o    Production and Other Specialized Services. We provide other specialized
     services that are required, or can be used effectively, in conjunction with
     the previously described basic services. These services may include
     provision of onsite temporary fluid-storage facilities, the provision,
     removal and disposal of specialized fluids used during certain completion
     and workover operations, and the removal and disposal of salt water that
     often is produced in conjunction with the production of oil and natural
     gas. On a limited basis we provide conventional coil tubing services used
     primarily to clean out wellbores. To complete the well life-cycle, we also
     provide plugging services for wells from which the oil and natural gas has
     been depleted or further production has become uneconomical.

         D.       OIL AND GAS INVESTMENTS.

Through our Ramshorn investments subsidiary, Nabors makes selective investments
in oil and gas exploration, development and production operations, most recently
with El Paso Corporation. On October 8, 2003, we entered into two separate
agreements with wholly-owned subsidiaries of El Paso Corporation under which a
subsidiary of Nabors will contribute 20% of an estimated $400 million total cost
to develop approximately 110 wells in exchange for a 20% net profits interest in
such wells (cash proceeds available from production after royalties and
operating costs have been paid). The wells included in these agreements include
a combination of proved undeveloped, probable and possible reserves located
primarily in South Texas, North Louisiana and Offshore Gulf of Mexico. In the
event that cash proceeds totaling 117.5% of our total investment are received
from the wells subject to the applicable agreement, our net profits interest in
those wells will convert to an overriding royalty interest of 0.4% in the wells
for the remainder of the wells' productive lives. Either party may terminate the
agreements upon 30 days' notice. El Paso will serve as operator of all the wells
covered in this development program.

On November 6, 2003, we entered into two additional agreements with El Paso to
drill up to a total of 12 exploratory wells in South Texas and South Louisiana.
Through these agreements and a subsequent election under one of the agreements,
we have committed to contribute 25% of El Paso's share of the cost of drilling
and completing eight of the wells; 25% of El Paso's share of the cost of
drilling to casing point for three of the wells; and 20% of El Paso's share of
the cost of drilling to casing point for one of the wells. We are also committed
to contribute 12.5% of El Paso's share of any other costs of the exploratory
wells and of all costs of any development wells in which we elect to participate
on those prospects. In exchange, we receive a 12.5% interest in El Paso's share
in the prospect leases where the exploratory wells are drilled, subject to
certain penalty deductions in the event we elect to participate in less than all
development wells drilled. As of December 31, 2003, three wells had commenced
drilling under these agreements with one being declared a dry hole, which
resulted in a charge to direct costs of $1.4 million recorded during the fourth
quarter of 2003. The other two wells are in various stages of completion, and an
independent third party has concluded that those wells are capable of production
in paying quantities.

         E.      OTHER SERVICES.

Through various subsidiaries and joint ventures, Nabors provides additional
well-site services that comprise our Other Operating Segment. These services can
be packaged with our contract drilling services or provided on a stand-alone
basis to operators or other contractors. They include top drive sales and
rentals, mudlogging services, rig instrumentation equipment rentals and sales,
rig reporting software, construction and maintenance services and transportation
services. Sales by these ancillary service providers to other Nabors companies
reduce our costs for similar third-party products and services. These units also
generate revenues through sales to third parties. The following is a summary of
our Other Services:

o    Top Drives. Our Canrig drilling technologies subsidiary manufactures top
     drives, which are installed on both onshore and offshore drilling rigs to
     improve drilling efficiency. Rigs equipped with top drives enjoy more
     finite control and directional orientation than rigs without, and can trip
     drill string in and out of the well faster and more safely by handling
     preassembled "doubles" and "triples" of pipe. Top drives also allow the
     drill string to be simultaneously hoisted and rotated, which provides
     better well control and reduces the incidence of stuck pipe, yielding time
     and cost savings.

o    Mudlogging, Rig Instrumentation and Software. Our EPOCH well services
     subsidiary offers rig instrumentation equipment, including sensors,
     proprietary RIGWATCH(TM) software and computerized equipment that monitors
     the real-time performance of a rig. In addition, EPOCH specializes in daily
     reporting



                                       6
<PAGE>


     software for drilling operations, making this data available through the
     internet via mywells.com. EPOCH also provides mudlogging services.
     Mudlogging involves the analysis of exhausted drill cuttings to discern
     certain information about the presence of hydrocarbons, rates of
     penetration and the nature of the formation. Our Ryan Energy Technologies
     subsidiary manufactures and sells directional drilling and rig
     instrumentation and data collection services to oil and gas exploration and
     service companies in Canada and provides directional drilling services in
     the United States.

o    Construction, Land Transportation and Related Services. Nabors has a 50%
     interest in Peak Oilfield Services Company, a general partnership with a
     subsidiary of Cook Inlet Region, Inc., a leading Alaskan native
     corporation. Peak Oilfield Services provides heavy equipment to move
     drilling rigs, water, other fluids and construction materials, primarily on
     Alaska's North Slope and in the Cook Inlet region. The partnership also
     provides construction and maintenance for ice roads, pads, facilities,
     equipment, drill sites and pipelines. In addition, the partnership provides
     tank cleaning services to oil customers along the Trans-Alaska pipeline and
     in the Valdez area. Peak Oilfield Services provides miscellaneous
     maintenance services for the Prudhoe Bay Unit. Our Peak USA subsidiary
     provides similar hauling and maintenance services for customers in the U.S.
     Lower 48. We also have an investment in an arctic road and site
     construction company.

o    Offshore Support Services. We time charter a fleet of offshore support
     vessels which provide marine transportation of drilling materials, supplies
     and crews for offshore rig operations and support for other offshore
     facilities and operations.

We provide onshore transportation and support services through long-term
contracts or on a short-term demand basis. Long-term service contracts may be
negotiated or awarded by competitive bidding. Whether provided on a long-term or
short-term basis, equipment and labor usually are billed separately at specified
hourly rates. These hourly rates vary depending upon numerous factors, including
types of equipment and labor, and duration of the work.

From time to time, we provide drilling engineering and integrated project
management services, ranging from well design and engineering expertise to site
preparation and road construction. We offer these services to help customers
eliminate or reduce management overhead which would otherwise be necessary to
supervise such services. Such services have not been significant in the past,
and are not expected to be significant in the near term.

         F.       OUR EMPLOYEES.

As of December 31, 2003, Nabors employed approximately 17,417 persons, of whom
approximately 2,046 were employed by unconsolidated affiliates. We believe our
relationship with our employees generally is good.

On October 18, 2000, the National Labor Relations Board confirmed the selection
of a collective bargaining representative at our Alaska drilling subsidiary. The
unit covers most non-supervisory drilling and related field personnel working on
or about our rigs within the State of Alaska. Negotiations with the union
commenced during 2000; an agreement was reached with representatives of the
union in December 2002; was submitted to the union membership for ratification;
and was rejected by the membership in the first quarter 2003. We anticipate that
the continuation of a collective bargaining unit at our Alaska drilling
subsidiary will not have any material adverse impact on the operations of that
entity or Nabors as a whole. During the first quarter 2003 the National Labor
Relations Board commenced a suit asserting that our subsidiary committed an
unfair labor practice in failing to adequately bargain with the collective
bargaining representative in connection with a change in Nabors' medical
insurance program. The administrative law judge who heard the case ruled in
Nabors' favor and the matter was appealed to an appeals panel of the National
Labor Relations Board, where it is currently pending. On February 10, 2004, the
Alaska State District Council of Laborers filed a charge with the National Labor
Relations Board alleging that our subsidiary committed an unfair labor practice
by threatening certain employees for the purpose of inducing them to alter a
Pro-Active Safety Report. In both of these matters, Nabors denies the
allegations, believes that it has meritorious defenses and further believes that
the outcome of the disputes will not have a material adverse effect on our
financial position, results of operations or cash flows.

Certain rig employees in Argentina and Australia are represented by collective
bargaining units.



                                       7
<PAGE>


         G.       SEASONALITY.

Our Canadian and Alaskan drilling and workover operations are subject to
seasonal variations as a result of weather conditions and generally experience
reduced levels of activity and financial results during the second calendar
quarter of each year. Seasonality does not have a material impact on the
remaining portions of our business. As our Canadian operations become a more
significant portion of our overall business, our overall financial results
should reflect the seasonal variations experienced in our Canadian and Alaskan
operations.

         H.       RESEARCH AND DEVELOPMENT.

Research and development does not constitute a material part of our overall
business. However, technology is of growing importance to our business and
management expects to maintain its competitive position technologically with the
internal development of technology or through strategic acquisitions.

Nabors' engineers obtained one new patent during early 2004 and have patent
applications pending for new technology associated with drilling activities. Our
patents generally cover designs for various types of oilfield equipment and
methods for conducting certain oilfield activities. We use some of these designs
and methods in the conduct of our business. The patents expire at various times
through the year 2021. We also have several trademarks and service marks that we
use in various aspects of our business. These include Sundowner(R), MASE(R) TRU
VU(R) and RIGWATCH TM. While management believes Nabors' patent and trademark
rights are valuable, their expiration or loss would not have a material adverse
effect on our financial position or results of operations. The costs associated
with our research and development are not material to Nabors.


III.     CUSTOMERS; MARKETS; INDUSTRY CONDITIONS AND TRENDS.

Our customers include major oil and gas companies, foreign national oil and gas
companies and independent oil and gas companies. No customer accounted for in
excess of 10% of consolidated revenues in 2003 or in 2002.

The majority of our business is conducted through our various Contract Drilling
operating segments, which include our drilling, workover and well-servicing
operations, on land and offshore. Our operating segments engaged in marine
transportation and supply services, drilling technology and top drive
manufacturing, directional drilling, rig instrumentation and software, and
construction and logistics operations are aggregated in a category labeled Other
Operating Segments for segment reporting purposes. Our limited oil and gas
exploration, development and production operations are included in a category
labeled Oil and Gas for segment reporting purposes.

Additional information regarding the geographic markets in which we operate and
our business segments can be found in Note 17 of the Notes to Consolidated
Financial Statements on pages 100 through 102 of our 2003 Annual Report and is
incorporated into this document by reference.

         A.       CONTRACT DRILLING.

                  1. ALASKA AND U.S. LOWER 48 LAND DRILLING. In Alaska, we
market 15 arctic land drilling, workover and well-servicing rigs on the North
Slope, and 3 land rigs and one platform rig in the Cook Inlet area of South
Central Alaska. Sixteen of these rigs are SCR rigs, and twelve are equipped with
top drive units. Fifteen are capable of performing drilling or workover
operations to depths of 15,000 feet or deeper.

All of the North Slope rigs are designed to operate in severe arctic conditions
and 14 employ wheel or track mounted systems engineered by Nabors to permit
efficient movement of the rigs from well to well and over ice or gravel roads.
Nine of these rigs are also partially or totally self-propelled to further
facilitate movement and maneuverability. Thirteen of the North Slope rigs have
been designed with spacing capability that allows them to move between reduced
well spacing on drilling pads without disrupting production. In addition, our
arctic rigs generally incorporate environmental protection features such as dry
mud and fluid containment systems.



                                       8
<PAGE>


We currently market approximately 280 drilling rigs in the U.S. Lower 48 market.
Approximately 150 of our land drilling rigs in the U.S. Lower 48 states are
diesel electric rigs controlled by a computerized SCR system. Approximately 200
are capable of drilling to 15,000 feet or deeper. In addition, we own 57
portable top drives for use on our rigs, depending on customer requirements.

Nabors had approximately 102 land drilling rigs and 244 workover/well-servicing
rigs stacked in the U.S. Lower 48 states at December 31, 2003.

                  2. U.S. LAND WELL-SERVICING. Our domestic land well-servicing,
workover and production services operation has locations in many of the major
oil and natural gas producing fields in the U.S. Lower 48 states. This operation
currently provides services in eight states and is divided into six separate
geographic districts: California, West Texas, East Texas, South Texas, Oklahoma,
and the Rocky Mountains. We actively market approximately 500 well-servicing
rigs in Texas, California, Oklahoma, New Mexico, North Dakota, Montana, Utah and
Louisiana.

                  3. U.S. OFFSHORE. Nabors currently performs domestic offshore
drilling and offshore workover and well-servicing through its subsidiaries. The
domestic offshore subsidiaries currently operate a fleet of 40 rigs, including
29 platform rigs (seven Sundowner(R) rigs, three 700 hp or below rigs, three
Super Sundowner(R) rigs, three concentric tubing rigs, three greater than 750 hp
rigs, six self-elevating drilling rigs and four API-style platform drilling
rigs), eight jack-up workover rigs and three inland barge rigs. Ten of our
platform rigs are capable of operating at well depths of 20,000 feet. Over half
of our platform rigs are specifically designed for workover drilling.

Most of our domestic offshore fleet operates in the U.S. Gulf of Mexico. The
remaining rigs are platforms operating offshore of California and Alaska.

                  4. CANADA. We have a fleet of 81 drilling rigs in Canada.
Twenty-seven rigs in the fleet are diesel electric SCR rigs, two are A/C
electric powered, 22 are equipped with top drives and 16 are capable of drilling
to 15,000 feet or deeper. Nabors also has a fleet of approximately 211 land well
servicing / workover rigs in Canada. Many of the rigs in our Canadian fleet are
capable of working under arctic and sub-arctic conditions.

                  5. INTERNATIONAL. We conduct our international operations
primarily through Nabors Drilling International Limited and its subsidiaries.
Internationally, we provide drilling, workover and well-servicing services, both
onshore and offshore, with specialized rigs designed and built to meet various
types of operating conditions. The International land group actively markets
approximately 53 land drilling rigs, 38 workover rigs and 2 well-servicing rigs.
Of these, over 39 are SCR rigs, 28 are equipped with top drives and 31 are
capable of drilling to depths of 15,000 feet or deeper. We operate 17 of these
rigs through a joint venture in Saudi Arabia (6 drilling and 11
workover/well-servicing rigs).

The International offshore group markets eight 1000 hp platform rigs, two 600 hp
platform rigs, three 2000 hp platform rigs and eight jack-up rigs. Five of the
1000 hp rigs and all the 2000 hp rigs are equipped with top drive units. We
currently operate one jack-up in Trinidad; one jack-up rig in Brazil; one 1000
hp platform rig in Australia; one 1000 hp platform rig in Congo; one 1000 hp
platform in Italy; three 1000 hp platform rigs, two 2000 hp platform rigs and
one jack-up rig in Mexico; one 1000 hp platform rig in Malaysia; one 2000 hp rig
in Indonesia; one 500 hp rig in India; and four jack-up rigs in the Middle East
(one of which is owned by our Saudi joint venture).

Additional information regarding our rig fleet can be found on pages 35 through
37 of the 2003 Annual Report.

         B.       OIL AND GAS SEGMENT.

As noted above under Description of Business - Oil and Gas Investments, we make
selective investments in oil and gas exploration, development and production
operations through our Ramshorn subsidiary. Although investment in oil and gas
exploration, development and production activities have not been and are not
expected to become a



                                       9
<PAGE>


significant part of our business, our agreements with El Paso Corporation
entered into in 2003 expanded our operations in this area.

Additional information regarding our Oil and Gas Segment can be found on pages
100 through 102 of the 2003 Annual Report.

         C.       OTHER OPERATING SEGMENTS.

We manufacture top drives at our Magnolia, Texas facility. We market our top
drives throughout the United States and Canada, and to various international
markets, to customers serving the oil and gas industry. In both 2003 and 2002,
31% of our top drive sales were made to other Nabors companies. We also rent top
drives and provide top drive installation, repair and maintenance services to
our customers.

We manufacture our rig instrumentation systems and develop our rig reporting and
related software in Houston, Texas. We sell or lease these products to customers
within the oil and gas industry, domestically and abroad. We provide mudlogging
services within the U.S. Lower 48 states and Alaska. Substantial portions of our
sales are made to other Nabors companies.

We also provide site and road construction, rig transportation, fluid hauling
and related oilfield services in Alaska, principally through our Peak Oilfield
Services joint venture. In the U.S. Lower 48 states we provide rig
transportation and related services through our Peak USA Energy Services
subsidiary, primarily to our domestic onshore drilling operations.

We time charter a fleet of 30 offshore support vessels and one crew boat, which
operate primarily in the Gulf of Mexico, and provide marine transportation of
drilling materials, supplies and crews for offshore rig operations and support
for other offshore facilities. The supply vessels are used as freight-carrying
vessels for drill pipe, tubing, casing, drilling mud and other equipment to
drilling rigs and production platforms.

Nabors' domestic onshore well-servicing and workover operation also provides
production services consisting chiefly of fluid hauling and fluid storage tank
rental. The production services assets, located primarily in Texas, consist of
over 300 fluid hauling trucks and ten salt water disposal wells, which are
utilized for the transportation and disposal of drilling and used completion
fluids and salt water produced from operating wells, and approximately 800 fluid
storage tanks, which are utilized for the storage of fluids used in the
fracturing of producing zones during the completion or workover of wells.

         D.       INDUSTRY CONDITIONS.

To a large degree, Nabors' businesses depend on the level of capital spending by
oil and gas companies for exploration, development and production activities. A
sustained increase or decrease in the price of natural gas or oil could have a
material impact on exploration, development and production activities by our
customers and could also affect materially our financial position, results of
operations and cash flows. See "Part I - Item 1 - Risk Factors - Fluctuations in
oil and gas prices could adversely affect drilling activity and Nabors'
revenues, cash flows and profitability."

Natural gas prices are the primary driver of our U.S. Lower 48 Land Drilling,
Canadian and U.S. Offshore (Gulf of Mexico) operations, while oil prices are the
primary driver of our Alaskan, International and U.S. Land Well-servicing
operations. The Henry Hub natural gas spot price (per Bloomberg) averaged $5.49
per million cubic feet (mcf) during 2003, up from a $3.37 per mcf average during
2002. West Texas intermediate spot oil prices (per Bloomberg) averaged $31.06
per barrel during 2003, up from a $26.17 per barrel average during 2002.

The contract drilling, workover and well-servicing industry has been cyclical
historically, with significant volatility in profitability and rig values. This
industry cyclicality has been due to changes in the level of domestic oil and
gas exploration and development activity and the available supply of drilling
rigs. From 1982 until 1996, the contract drilling business was severely impacted
by the decline and continued instability in the prices of oil and natural gas
following a period of significant increase in new drilling rig capacity. Rising
prices in 1997 gave way to a steep



                                       10
<PAGE>


decline that continued through 1998 and most of 1999. The market again improved
substantially in 2000 and the first half of 2001, but experienced a rapid
contraction in late 2001 and early 2002 illustrating the dependence of the
industry on natural gas and oil prices. The industry has improved again since
mid-2002 to the point where, by the end of 2003, it was operating at a rate that
approximated 2001 activity, although pricing was lower because of additional
capacity added within the industry since 2001.

Our operating results for 2004 are expected to increase from levels realized
during 2003 given our current expectations of commodity prices and the related
impact on drilling and well-servicing activity during 2004. The expected
increase in drilling activity is expected to have the largest impact on our
Canadian and U.S. Lower 48 Land Drilling operations. We also expect an
improvement in operating results for our U.S. Offshore (Gulf of Mexico)
operations during 2004 primarily as a result of incremental revenues from three
new platform rigs for deepwater development projects that we expect to commence
operations during the first half of 2004, as well as a recovery in the level of
overall activity in this market. We expect results from our International
operations for 2004 to increase slightly as a result of a full year of
operations for contracts in India and Indonesia, which began in the last half of
2003, and a full year of operations in Mexico where rigs commenced operations
over the first three quarters of 2003. We also expect to see a number of rigs
that had been operating under long-term contracts for our International
operations that were unexpectedly idled in late 2003, return to work during
2004. Our U.S. Land Well-servicing operations are expected to maintain a steady
to slightly upward trend for 2004 given our current expectations of commodity
prices during 2004 as discussed above. We expect results from our operations in
Alaska to be reduced overall during 2004 compared to 2003, as two of our rigs
are nearing completion on contracts that have not yet been renewed or replaced.

         E.       COMPETITIVE CONDITIONS.

Our industry remains very competitive. The number of rigs continues to exceed
demand in many of our markets, resulting in strong price competition. Many rigs
can be readily moved from one region to another in response to changes in levels
of activity, which may result in an oversupply of rigs in such areas. Many of
the total available contracts are currently awarded on a bid basis, which
further increases competition based on price. The land drilling, workover and
well-servicing market is generally more competitive than the offshore market due
to the larger number of rigs and market participants.

In all of our geographic market areas, we believe price and availability and
condition of equipment are the most significant factors in determining which
drilling contractor is awarded a job. Other factors include the availability of
trained personnel possessing the required specialized skills; the overall
quality of service and safety record; and domestically, the ability to offer
ancillary services. In international markets, experience in operating in certain
environments and customer alliances also have been factors in the selection of
Nabors.

Certain competitors are present in more than one of Nabors' operating regions,
although no one competitor operates in all of these areas. In the U.S. Lower 48
states, there are several hundred competitors with smaller national, regional or
local rig operations. In domestic land workover and well-servicing, we compete
with Key Energy Services, Inc., which owns over 1,400 U.S. workover and
well-servicing rigs (according to its public filings), and with numerous other
competitors having smaller regional or local rig operations. In the Alaska
market, Nabors has two primary competitors, Doyon Drilling, Inc. and Nordic
Calista Services. Kuukpik Drilling has also made attempts to enlarge its
presence in this market. In Canada and offshore, Nabors competes with many firms
of varying size, several of which have more significant operations in those
areas than Nabors. Internationally, Nabors competes directly with various
contractors at each location where it operates. Nabors believes that the market
for land drilling, workover and well-servicing contracts will continue to be
competitive for the foreseeable future. Although Nabors believes it has a strong
competitive position in the domestic land drilling, workover and well-servicing
sector, certain of our competitors internationally and offshore may be better
positioned in certain markets, allowing them to compete more effectively.

Our other operating segments represent a relatively smaller part of our
business, and we have numerous competitors in each area in which we operate who
may have greater resources and may be better positioned than Nabors. Our Canrig
subsidiary is one of the six major manufacturers of top drives. Its largest
competitors are Varco, Tesco and



                                       11
<PAGE>
National Oilwell. EPOCH's largest competitor in the manufacture of rig
instrumentation systems is Varco's Totco subsidiary. Mudlogging services are
provided by a number of entities that serve the oil and gas industry on a
regional basis. EPOCH competes for mudlogging customers with Sperry Sun and
Baker Hughes in the Gulf Coast region, California and Alaska. In the U.S. Lower
48 states, there are hundreds of rig transportation companies, and there are at
least three or four that compete with Peak USA in each of its operating regions.
In Alaska, Peak Oilfield Services principally competes with Alaska Petroleum
Contractors for road, pad and pipeline maintenance, and is one of many drill
site and road construction companies, the largest of which is VECO Corporation.

IV.      RECENT DEVELOPMENTS.

         A.       OPERATING RESULTS.

Operating revenues and Earnings from unconsolidated affiliates for 2003 totaled
$1.9 billion, representing an increase of $409.0 million, or 28%, compared to
2002. Net income for 2003 totaled $192.2 million ($1.25 per diluted share),
representing an increase of 58% compared to 2002.

The increase in our Operating revenues and Earnings from unconsolidated
affiliates during 2003 primarily resulted from higher revenues realized by our
Canadian, U.S. Lower 48 Land Drilling and International operations. The improved
revenues from our Canadian operations resulted from an increase in the level of
activity for our land drilling and well-servicing operations driven by increased
demand for our services in that market during 2003 and our acquisition of
Enserco Energy Service Company Inc. in April 2002. The Enserco acquisition
increased the number of drilling rigs owned and operated by Nabors in Canada by
30 drilling rigs while also adding over 200 well-servicing rigs. The improved
revenues for our U.S. Lower 48 Land Drilling operations resulted from higher
activity levels driven by a gradual increase in demand for drilling services in
that market during 2003. The overall increase in demand in these markets was
driven by higher average price levels for natural gas in 2003 compared to 2002.
International revenues improved primarily as a result of six new long-term
contracts for our operation in Mexico.

The increase in net income during 2003 primarily resulted from the increase in
revenues discussed above and a lower effective tax rate. However, the overall
increase in net income for 2003 was partially offset by lower average dayrates
in our U.S. Lower 48 Land Drilling operations during 2003 and lower margins
realized by certain of our Other Operating Segments. The decrease in average
dayrates for our U.S. Lower 48 Land Drilling operations resulted from dayrates
declining during 2002 and remaining flat until the latter part of 2003, when
dayrates began to rise. The decline in dayrates during 2002 resulted from the
weakness in this market over the period beginning in the third quarter of 2001
and extending through the end of 2002.

Additional information regarding our financial condition and results can be
found on pages 49 through 56 of the Nabors Industries Ltd. 2003 Annual Report,
under the caption "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Results of Operations".

         B.       DEBT OFFERING AND DEBT REDEMPTIONS.

On June 10, 2003, Nabors Delaware, our wholly-owned subsidiary, completed a
private placement of $700 million aggregate principal amount of zero coupon
senior exchangeable notes due 2023 that are fully and unconditionally guaranteed
by us. The notes were reoffered by the initial purchaser of the notes to
qualified institutional buyers under Rule 144A of the Securities Act of 1933, as
amended, and outside the United States in accordance with Regulation S under the
Securities Act. The notes do not bear interest, do not accrete and have a zero
yield to maturity, unless Nabors Delaware becomes obligated to pay contingent
interest as defined in the note indenture.

The notes are exchangeable at the option of the holders into 14.2653 common
shares of Nabors per $1,000 principal amount of notes (subject to adjustment for
certain events) if certain conditions are satisfied (including certain
conditions relating to the price per share of Nabors common shares). A more
complete description of the terms of the notes can be found in Note 8 of the
Notes to Consolidated Financial Statements on pages 87 through 90 of our Annual
Report and is incorporated into this document by reference.



                                       12
<PAGE>


We used a portion of the net proceeds from the issuance of the notes to redeem
the remaining outstanding principal amount of Nabors Delaware's $825 million
zero coupon convertible senior debentures due 2020 on June 20, 2003 and our
associated guarantees. The redemption price was $655.50 per $1,000 principal
amount of the debentures for an aggregate redemption price paid of approximately
$494.9 million. The redemption of the debentures did not result in any gain or
loss as the debentures were redeemed at prices equal to their carrying value on
June 20, 2003. The remainder of the proceeds of the notes were invested in cash
and marketable securities.

On April 1, 2003, we redeemed our 8.625% senior subordinated notes due April
2008 and all associated guarantees at a redemption price of $1,043.13 per $1,000
principal amount of the notes together with accrued and unpaid interest to the
date of redemption. The aggregate redemption price was $45.2 million and
resulted in the recognition of a pretax loss of approximately $.9 million,
resulting from the redemption of the notes at prices higher than their carrying
value on April 1, 2003.

         C.       OIL AND GAS INVESTMENTS.

On October 8, 2003, we entered into two separate agreements with wholly-owned
subsidiaries of El Paso Corporation under which a subsidiary of Nabors will
contribute 20% of an estimated $400 million total cost to develop approximately
110 wells in exchange for a 20% net profits interest in such wells (cash
proceeds available from production after royalties and operating costs have been
paid). The wells included in these agreements include a combination of proved
undeveloped, probable and possible reserves located primarily in South Texas,
North Louisiana and Offshore Gulf of Mexico. In the event that cash proceeds
totaling 117.5% of our total investment are received from the wells subject to
the applicable agreement, our net profits interest in those wells will convert
to an overriding royalty interest of 0.4% in the wells for the remainder of the
wells' productive lives. Either party may terminate the agreements upon 30 days'
notice. El Paso will serve as operator of all the wells covered in this
development program.

On November 6, 2003, we entered into two additional agreements with El Paso to
drill up to a total of 12 exploratory wells in South Texas and South Louisiana.
Through these agreements and a subsequent election under one of the agreements,
we have committed to contribute 25% of El Paso's share of the cost of drilling
and completing eight of the wells; 25% of El Paso's share of the cost of
drilling to casing point for three of the wells; and 20% of El Paso's share of
the cost of drilling to casing point for one of the wells. We are also committed
to contribute 12.5% of El Paso's share of any other costs of the exploratory
wells and of all costs of any development wells in which we elect to participate
on those prospects. In exchange, we receive a 12.5% interest in El Paso's share
in the prospect leases where the exploratory wells are drilled subject to
certain penalty deductions in the event we elect to participate in less than all
development wells drilled. As of December 31, 2003, three wells had commenced
drilling under these agreements with one being declared a dry hole, which
resulted in a charge to direct costs of $1.4 million recorded during the fourth
quarter of 2003. The other two wells are in various stages of completion, and an
independent third party has concluded that those wells are capable of producing
in paying quantities.

V.       OUR BUSINESS STRATEGY.

Since 1987, with the installation of our current management team, Nabors has
adhered to a consistent strategy aimed at positioning our company to grow and
prosper in good times and to mitigate adverse effects during periods of poor
market conditions. We have continued to strive to attain a financial posture
that would allow us to capitalize on market weakness by adding to our business
base, thereby enhancing our upside potential at reasonable costs. The principal
elements of our strategy have been to:

     o    Maintain flexibility to respond to changing conditions.

     o    Maintain a conservative and flexible balance sheet.

     o    Build cost effectively a base of premium assets.

     o    Build and maintain low operating costs through economies of scale.

     o    Develop and maintain long-term, mutually attractive relationships with
          key customers and vendors.

     o    Build a diverse business in long-term, sustainable and worthwhile
          geographic markets.

     o    Recognize and seize opportunities as they arise.

     o    Continually improve safety, quality and efficiency.

     o    Implement leading edge technology where cost-effective to do so.

Our business strategy is designed to allow us to grow and remain profitable in
any market environment. The major developments in our business in the past year
illustrate our implementation of this strategy and its continuing success.
Following is a discussion of recent events evidencing several of these
strategies.



                                       13
<PAGE>


MAINTAINING A CONSERVATIVE AND FLEXIBLE BALANCE SHEET - During 2003 we completed
a private placement of $700 million aggregate principal amount of zero coupon
exchangeable notes due 2023 through a wholly owned subsidiary. We also redeemed
the remaining principal amount of our $825 million zero coupon convertible
senior debentures due 2020 (reducing our average diluted share count by
approximately eight million shares) and redeemed our 8.625% senior subordinated
notes due April 2008. (See discussion above under Recent Developments.) Our 6.8%
Senior Notes are due in April 2004 and their maturity will further reduce our
average cost of capital.

RECOGNIZING OPPORTUNITY -- Our Enserco and Ryan acquisitions completed during
2002 expanded our presence in Canada and added to our technological capabilities
that can be shared across the Nabors group of companies.

SAFETY -- In the drilling and oilfield service business, safety and loss control
are critical to overall performance. The safety and health of Nabors' employees
are of paramount importance. Nabors intensified its safety and loss control
program in 1997 with its U.S. Lower 48 drilling operations, and expanded the
enhanced program to the other business units during the last half of 2000. The
enhanced programs were largely carried out in 2001 and are becoming further
embedded in Nabors culture. Improvements have already been achieved as evidenced
by our total OSHA (Occupational Safety and Health Administration) recordable
incident rate (see chart below).

During 2002 and 2003 Nabors' international drilling subsidiary completed a
three-year development of an ISO 9000 compatible Rig Management Systems quality
program. Nabors' offshore operations have adopted the same program. Nabors
increased pre-employment and on-the-job training initiatives during 2003 in
connection with increased activity levels and to emphasize its commitment to
safe operations. Although it is impossible to predict what incident rates will
be in the future, improvement in our safety procedures is an important part of
Nabors' business strategy.

<Table>
<Caption>
                   OSHA Recordable    Incident Rates*
                   ---------------    ---------------
<S>                                   <C>
                        1997               7.80
                        1998               5.50
                        1999               3.43
                        2000               3.65
                        2001               2.99
                        2002               2.43
                        2003               2.76
</Table>

     * The OSHA recordable incident rate is equal to number of OSHA recordable
     incidents multiplied by 200,000 man-hours divided by the actual number of
     man-hours worked for the period.


VI.      RISK FACTORS

In addition to the other information set forth elsewhere in this Form 10-K, the
following factors should be carefully considered when evaluating Nabors.

FLUCTUATIONS IN OIL AND GAS PRICES COULD ADVERSELY AFFECT DRILLING ACTIVITY AND
OUR REVENUES, CASH FLOWS AND PROFITABILITY

Our operations are materially dependent upon the level of activity in oil and
gas exploration and production. Both short-term and long-term trends in oil and
gas prices affect the level of such activity. Oil and gas prices and, therefore,
the level of drilling, exploration and production activity can be volatile.
Worldwide military, political and economic events, including initiatives by the
Organization of Petroleum Exporting Countries, may affect both the demand for,
and the supply of, oil and gas. Weather conditions, governmental regulation
(both in the United States and elsewhere), levels of consumer demand, the
availability of pipeline capacity, and other factors beyond our control may also
affect the supply of and demand for oil and gas. Fluctuations during the last
few years in the



                                       14
<PAGE>


demand and supply of oil and gas have contributed to, and are likely to continue
to contribute to, price volatility. We believe that any prolonged reduction in
oil and gas prices would depress the level of exploration and production
activity. This would likely result in a corresponding decline in the demand for
our services and could have a material adverse effect on our revenues, cash
flows and profitability. Lower oil and gas prices could also cause our customers
to seek to terminate, renegotiate or fail to honor our drilling contracts;
affect the fair market value of our rig fleet which in turn could trigger a
writedown for accounting purposes; affect our ability to retain skilled rig
personnel; and affect our ability to obtain access to capital to finance and
grow our business. There can be no assurances as to the future level of demand
for our services or future conditions in the oil and gas and oilfield services
industries.

WE OPERATE IN A HIGHLY COMPETITIVE INDUSTRY WITH EXCESS DRILLING CAPACITY, WHICH
MAY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS

The oilfield services industry in which we operate is very competitive. Contract
drilling companies compete primarily on a regional basis, and competition may
vary significantly from region to region at any particular time. Many drilling,
workover and well-servicing rigs can be moved from one region to another in
response to changes in levels of activity and provided market conditions
warrant, which may result in an oversupply of rigs in an area. In many markets
in which we operate, the number of rigs available for use exceeds the demand for
rigs, resulting in price competition. Most drilling and workover contracts are
awarded on the basis of competitive bids, which also results in price
competition. The land drilling market generally is more competitive than the
offshore drilling market because there are larger numbers of rigs and
competitors.

Certain competitors are present in more than one of the regions in which we
operate, although no one competitor operates in all of these areas. In the U.S.
Lower 48 states, there are several hundred competitors with smaller national,
regional or local rig operations. In the Alaska market, we have two principal
competitors. In Canada and offshore, we compete with several firms of varying
size, many of which have more significant operations in those areas than us.
Internationally, we compete directly with various competitors at each location
where we operate. We believe that the market for land drilling and workover
contracts will continue to be competitive for the foreseeable future. Certain of
our competitors internationally and offshore may be better positioned in certain
markets, allowing them to compete more effectively.

THE NATURE OF OUR OPERATIONS PRESENTS INHERENT RISKS OF LOSS THAT, IF NOT
INSURED OR INDEMNIFIED AGAINST, COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS

Our operations are subject to many hazards inherent in the drilling, workover
and well-servicing industries, including blowouts, cratering, explosions, fires,
loss of well control, loss of hole, damaged or lost drilling equipment and
damage or loss from inclement weather or natural disasters. Any of these hazards
could result in personal injury or death, damage to or destruction of equipment
and facilities, suspension of operations, environmental damage and damage to the
property of others. Our offshore operations are also subject to the hazards of
marine operations including capsizing, grounding, collision, damage from heavy
weather or sea conditions and unsound ocean bottom conditions. In addition, our
international operations are subject to risks of war, civil disturbances or
other political events. Generally, drilling contracts provide for the division
of responsibilities between a drilling company and its customer, and we seek to
obtain indemnification from our customers by contract for certain of these
risks. To the extent that we are unable to transfer such risks to customers by
contract or indemnification agreements, we seek protection through insurance.
However, there is no assurance that such insurance or indemnification agreements
will adequately protect us against liability from all of the consequences of the
hazards described above. The occurrence of an event not fully insured or
indemnified against, or the failure of a customer or insurer to meet its
indemnification or insurance obligations, could result in substantial losses. In
addition, there can be no assurance that insurance will be available to cover
any or all of these risks, or, even if available, that it will be adequate or
that insurance premiums or other costs will not rise significantly in the
future, so as to make such insurance prohibitive. This is particularly of
concern in the wake of the September 11, 2001 terrorist attacks, which adversely
affected an already tightening insurance market. It is likely that we will face
continued upward pressure in our upcoming insurance renewals, our premiums and
deductibles will be higher, and certain insurance coverage either will be
unavailable or more expensive than it has been in the past. Moreover, our
insurance coverage generally provides that we assume a portion of the risk in
the form of an insurance coverage



                                       15
<PAGE>


deductible. We expect that we may choose to increase the levels of deductibles
(and thus assume a greater degree of risk) from time to time in order to
minimize the effect of insurance premium increases.

THE PROFITABILITY OF OUR INTERNATIONAL OPERATIONS COULD BE ADVERSELY AFFECTED BY
WAR, CIVIL DISTURBANCE OR POLITICAL OR ECONOMIC TURMOIL

We derive a significant portion of our business from international markets,
including major operations in Canada, the Middle East, the Far East and South
and Central America. These operations are subject to various risks, including
the risk of war, civil disturbances and governmental activities that may limit
or disrupt markets, restrict the movement of funds or result in the deprivation
of contract rights or the taking of property without fair compensation. In
certain countries, our operations may be subject to the additional risk of
fluctuating currency values and exchange controls. In the international markets
in which we operate, we are subject to various laws and regulations that govern
the operation and taxation of our business and the import and export of our
equipment from country to country, the imposition, application and
interpretation of which can prove to be uncertain.

PROPOSED TAX LEGISLATION COULD ELIMINATE THE BENEFITS OF OUR REORGANIZATION

Various bills have been introduced in Congress that would retroactively
eliminate the tax benefits associated with our reorganization as a Bermuda
company. Because we cannot predict whether legislation ultimately will be
adopted, no assurances can be given that the tax benefits associated with our
reorganization ultimately will accrue to the benefit of the company and its
shareholders. If legislation is enacted that retroactively eliminates the
benefit of the reorganization, our net operating loss carryforward for U.S. tax
purposes would be reduced significantly and our effective tax rate in future
periods could be increased significantly.

NONCOMPLIANCE WITH GOVERNMENTAL REGULATION OR EXPOSURE TO ENVIRONMENTAL
LIABILITIES COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS

The drilling of oil and gas wells is subject to various federal, state, local
and foreign laws, rules and regulations. Our cost of compliance with these laws
and regulations may be substantial. For example, federal law imposes specific
design and operational standards on rigs and platforms. Failure to comply with
these requirements could subject us to substantial civil and criminal penalties
as well as potential court injunctions. In addition, federal law imposes a
variety of regulations on "responsible parties" related to the prevention of oil
spills and liability for damages from such spills. As an owner and operator of
onshore and offshore rigs and transportation equipment, we may be deemed to be a
responsible party under federal law. In addition, our well-servicing, workover
and production services operations routinely involve the handling of significant
amounts of waste materials, some of which are classified as hazardous
substances. Our operations and facilities are subject to numerous state and
federal environmental laws, rules and regulations, including, without
limitation, laws concerning the containment and disposal of hazardous
substances, oilfield waste and other waste materials, the use of underground
storage tanks and the use of underground injection wells. We generally require
our customers contractually to assume responsibility for compliance with
environmental regulations. However, we are not always successful in allocating
to our customers all of these risks nor is there any assurance that the customer
will be financially able to bear those risks assumed.

We employ personnel responsible for monitoring environmental compliance and
arranging for remedial actions that may be required from time to time and also
use outside experts to advise on and assist with our environmental compliance
efforts. Costs we incur to investigate and remediate contaminated sites are
expensed unless the remediation extends the useful lives of the assets employed
at the site. Remediation costs that extend the useful lives of the assets are
capitalized and amortized over the remaining useful lives of such assets.
Liabilities are recorded when the need for environmental assessments and/or
remedial efforts become known or probable and the cost can be reasonably
estimated.

Laws protecting the environment generally have become more stringent than in the
past and are expected to continue to become more so. Violation of environmental
laws and regulations can lead to the imposition of administrative, civil or
criminal penalties, remedial obligations; and in some cases injunctive relief.
Such violations could also result in liabilities for personal injuries, property
damage, and other costs and claims.



                                       16
<PAGE>


Under the Comprehensive Environmental Response, Compensation and Liability Act,
also known as CERCLA or Superfund, and related state laws and regulations,
liability can be imposed jointly on the entire group of responsible parties or
separately on any one of the responsible parties, without regard to fault or the
legality of the original conduct on certain classes of persons that contributed
to the release of a "hazardous substance" into the environment. Under CERCLA,
such persons may be liable for the costs of cleaning up the hazardous substances
that have been released into the environment and for damages to natural
resources, and it is not uncommon for the neighboring land owners and other
third parties to file claims for personal injury, property damage and recovery
of response costs allegedly caused by the hazardous substances released into the
environment. We have been notified of our possible responsibility with respect
to the cleanup of a federal national priority list site and a state abandoned
site, which were formerly operated by parties unrelated to us as oilfield waste
disposal facilities. In addition, we have been named as a potentially
responsible party with respect to the cleanup of three other sites, which were
formerly operated by various parties unrelated to us. We believe that our cost
to clean up each of these sites will be less than $100,000. Although at this
time information regarding our possible responsibility with respect to cleanup
of the federal national priority list site and the state abandoned site has not
been fully developed and it is not feasible to predict such outcome with
certainty, we are of the opinion that the ultimate resolution of these matters
should not have a material adverse effect on our financial position, results
of operations or cash flows.

Changes in federal and state environmental regulations may also negatively
impact oil and natural gas exploration and production companies, which in turn
could have a material adverse effect on us. For example, legislation has been
proposed from time to time in Congress which would reclassify certain oil and
natural gas production wastes as hazardous wastes, which would make the
reclassified wastes subject to more stringent handling, disposal and clean-up
requirements. If enacted, such legislation could dramatically increase operating
costs for oil and natural gas companies and could reduce the market for our
services by making many wells and/or oilfields uneconomical to operate.

The Oil Pollution Act of 1990, as amended, contains provisions specifying
responsibility for removal costs and damages resulting from discharges of oil
into navigable waters or onto the adjoining shorelines. Among other
requirements, this law requires owners and operators of vessels over 300 gross
tons to provide the U.S. Coast Guard with evidence of financial responsibility
to cover the costs of cleaning up oil spills from such vessels. We believe we
have provided satisfactory evidence of financial responsibility to the U.S.
Coast Guard for all vessels over 300 tons. In addition, the Outer Continental
Shelf Lands Act provides the federal government with broad discretion in
regulating the leasing of offshore oil and gas production sites. Because our
offshore support vessel operations rely on offshore oil and gas exploration and
production, if the government were to exercise its authority under this law to
restrict the availability of offshore oil and gas leases, such an action could
have a material adverse effect on our offshore support vessel operations.

PROPOSED COAST GUARD REGULATIONS AND ACTIONS COULD CURTAIL OUR ABILITY TO TIME
CHARTER VESSELS IN U.S. COASTWISE TRADE.

Our Sea Mar division time charters supply vessels to offshore operators in U.S.
waters. On February 4, 2004, the United States Coast Guard took several actions
which could adversely affect our ability to do so.

The vessels are owned by one of our financing company subsidiaries, but are
operated and managed by a U.S. citizen-controlled company pursuant to long-term
bareboat charters. Our Sea Mar division time charters the vessels from this U.S.
operating company in connection with our own offshore activities in the Gulf of
Mexico and in support of other offshore operators.

On February 4, 2004, the United States Coast Guard adopted final regulations
which could cause arrangements like that utilized by Sea Mar to no longer
qualify vessels for employment in the U.S. coastwise trades. However, the final
regulations contain grandfathering provisions which could permit us to continue
coastwise marketing of the vessels until the present bareboat charters
terminate. The original term of most of these bareboat charters ends in June
2007, but the charter provides for one or more renewal terms of three to five
years. We believe the grandfathering provisions in these final regulations would
apply to these renewal terms.



                                       17
<PAGE>


Also, on February 4, 2004, the United States Coast Guard proposed a rule which,
if finally adopted, would end the grandfathering provision on February 4, 2007.
In these same proposed regulations, the United States Coast Guard is proposing a
rule under which time charters from a U.S. citizen bareboat charterer like the
charter to Sea Mar would no longer be permitted. However, we believe that if
this rule is adopted, the grandfathering provision would apply to the
preexisting Sea Mar arrangement.

Additionally, on February 4, 2004, the United States Coast Guard notified us
that it is considering an appeal of the United States Coast Guard's original
issuance in June 2002 of the coastwise trade endorsements for the vessels
bareboat chartered to the U.S. citizen qualified company. The coastwise trade
endorsements on the documents of the vessels issued by the United States Coast
Guard authorize the vessels to engage in the U.S. coastwise trade. If the appeal
is decided against us, we could lose the ability to market the vessels for use
in U.S. waters.

During 2003, net income for our Sea Mar division represented approximately 3.8%
of our consolidated net income. We currently expect that this percentage will
decrease to approximately 0.7% in 2004.

AS A HOLDING COMPANY, WE DEPEND ON OUR SUBSIDIARIES TO MEET OUR FINANCIAL
OBLIGATIONS

We are a holding company with no significant assets other than the stock of our
subsidiaries. In order to meet our financial needs, we rely exclusively on
repayments of interest and principal on intercompany loans made by us to our
operating subsidiaries and income from dividends and other cash flow from such
subsidiaries. There can be no assurance that our operating subsidiaries will
generate sufficient net income to pay upstream dividends or cash flow to make
payments of interest and principal to us in respect of their intercompany loans.
In addition, from time to time, our operating subsidiaries may enter into
financing arrangements which may contractually restrict or prohibit such
upstream payments to us. There may also be adverse tax consequences associated
with making dividend payments upstream.

WE DO NOT PAY DIVIDENDS

We have not paid any cash dividends on our common shares since 1982. We do not
anticipate that we will pay any cash dividends on our common shares in the
foreseeable future.

BECAUSE OUR OPTION, WARRANT AND CONVERTIBLE SECURITIES HOLDERS HAVE A
CONSIDERABLE NUMBER OF COMMON SHARES AVAILABLE FOR ISSUANCE AND RESALE,
SIGNIFICANT ISSUANCES OR RESALES IN THE FUTURE MAY ADVERSELY AFFECT THE MARKET
PRICE OF OUR COMMON SHARES

As of February 29, 2004, we had 400,000,000 authorized common shares, of which
148,047,219 shares were outstanding. In addition, 34,439,582 common shares were
reserved for issuance pursuant to option and employee benefit plans, and
18,476,525 shares were reserved for issuance upon conversion or repurchase of
outstanding zero coupon convertible debentures and zero coupon senior
exchangeable notes. In addition, in connection with our Enserco and Ryan
acquisitions, up to 372,108 of our common shares could be issuable on
exchange of the shares of Nabors Exchangeco (Canada) Inc. We also may sell up to
$700 million of securities of various types in connection with a shelf
registration statement declared effective on January 16, 2003 by the Securities
and Exchange Commission. The sale, or availability for sale, of substantial
amounts of our common shares in the public market, whether directly by us or
resulting from the exercise of warrants or options (and, where applicable, sales
pursuant to Rule 144) or to the conversion into, or repurchase of debentures and
notes using, common shares, would be dilutive to existing security holders,
could adversely affect the prevailing market price of our common shares and
could impair our ability to raise additional capital through the sale of equity
securities.

PROVISIONS OF OUR ORGANIZATIONAL DOCUMENTS MAY DETER A CHANGE OF CONTROL
TRANSACTION AND DECREASE THE LIKELIHOOD OF A SHAREHOLDER RECEIVING A CHANGE OF
CONTROL PREMIUM

Our board of directors is divided into three classes, with each class serving a
staggered three-year term. In addition, our board of directors has the authority
to issue a significant amount of common shares and up to 25,000,000 preferred
shares and to determine the price, rights (including voting rights), conversion
ratios, preferences and



                                       18
<PAGE>


privileges of the preferred shares, in each case without further vote or action
by the holders of the common shares. Although we have no present plans to issue
preferred shares, the classified board and our board's ability to issue
additional preferred shares may discourage, delay or prevent changes in control
of Nabors that is not supported by our board, thereby possibly preventing
certain of our shareholders from realizing a possible premium on their shares.

WE HAVE A SUBSTANTIAL AMOUNT OF DEBT OUTSTANDING

We had approximately $2.3 billion in debt outstanding at December 31, 2003,
resulting in a funded debt-to-capital ratio of 0.48:1 and a net funded
debt-to-capital ratio of 0.23:1. The funded debt-to-capital ratio is calculated
by dividing funded debt by funded debt plus capital. Funded debt is defined as
the sum of (1) short-term borrowings, (2) the current portion of long-term debt
and (3) long-term debt. Capital is defined as shareholders' equity. The net
funded debt-to-capital ratio nets cash and cash equivalents and marketable
securities ($1.5 billion as of December 31, 2003) against funded debt. This
ratio is calculated by dividing net funded debt by net funded debt plus capital.
Both of these ratios are a method for calculating the amount of leverage a
company has in relation to its capital.


VII.     ACQUISITIONS AND DIVESTITURES.

We have grown from a land drilling business centered in the U.S. Lower 48,
Canada and Alaska to an international business with operations on land and
offshore in many of the major oil, gas and geothermal markets in the world. At
the beginning of 1990, our fleet consisted of 44 land drilling rigs in Canada,
Alaska and in various international markets. Today, Nabors' worldwide fleet
consists of almost 600 land drilling rigs, approximately 750 domestic and 211
international land workover and well-servicing rigs, 45 offshore platform rigs,
16 jack-ups, three barge rigs and a large component of trucks and fluid hauling
vehicles. This growth was fueled in part by strategic acquisitions, as
summarized in the following chart:

<Table>
<Caption>
DATE            ACQUIRED OR SELLING ENTITY         ASSETS ACQUIRED(1)                LOCATIONS
--------------  ---------------------------------  --------------------------------  --------------------------------
<S>             <C>                                <C>                               <C>
       3/1990   Loffland Brothers Company          63 land drilling rigs; yards;     North Sea, Middle East,
                                                   miscellaneous equipment and       Canada, U.S. Lower 48, Gulf of
                                                   inventory; financial assets       Mexico, Venezuela

      11/1990   Henley Drilling Co.                11 land drilling rigs             U.S. Lower 48, Yemen

       6/1993   Grace Drilling Co.                 110 land drilling rigs; yards;    U.S. Lower 48
                                                   miscellaneous equipment
                                                   and inventory

       4/1994   MND Drilling                       16 land drilling rigs             U.S. Lower 48

      10/1994   Sundowner Offshore Services, Inc.  15 platform rigs, 1 platform      Gulf of Mexico, International
                                                   rig under construction, 5
                                                   jack-up workover rigs, 3
                                                   workover and plug and
                                                   abandonment barges

         1994   Various                            8 mobile, medium-depth land       U.S. Lower 48
                                                   drilling rigs

       1/1995   Delta Drilling Company             30 land drilling rigs (15 SCR,    Texas, Louisiana
                                                   15,000+ capable depth), yards
                                                   and office facilities

       4/1996   Exeter Drilling Company            49 shallow and medium-depth       United States (47),
                                                   land drilling rigs                International (2)

       4/1996   J.W. Gibson Well Servicing         78 workover and well-servicing    Rocky Mountains, Mid-continent
                Company(2)                         rigs (10 leased from third        Region
                                                   parties)

      11/1996   EPOCH Well Logging, Inc.           Mudlogging units                  Not applicable

      12/1996   Noble Drilling                     47 land drilling rigs (19         United States (38),
                Company                            operating and 28 stacked);        Canada (9)
                                                   yards; equipment and inventory
</Table>



                                       19
<PAGE>
<Table>
<Caption>
DATE            ACQUIRED OR SELLING ENTITY         ASSETS ACQUIRED(1)                LOCATIONS
--------------  ---------------------------------  --------------------------------  --------------------------------
<S>             <C>                                <C>                               <C>
       1/1997   Adcor-Nicklos Drilling             36 land drilling rigs (30         U.S. Lower 48
                Company                            active, 6 stacked, including 14
                                                   SCR), equipment, drill pipe,
                                                   yards, vehicles and support
                                                   equipment

       4/1997   Chesley Pruet Drilling Company     12 land drilling rigs (10         Alabama, Louisiana, Mississippi
                                                   active, 2 stacked, including 9
                                                   SCR)

       4/1997   Samson Rig Company                 25 stacked SCR land rigs and      Oklahoma
                                                   large component of equipment

       8/1997   Cleveland Drilling Company, Inc.   7 land drilling rigs (6 active,   California, Nevada
                                                   1 stacked, including 6 SCR rigs)

      11/1997   VECO Drilling, Inc.;               6 land drilling rigs (5 active,   California, Texas
                Diamond L                          1 stacked, including 3 SCR) and
                                                   two offshore labor contracts; 3
                                                   active mechanical rigs

      12/1997   C.A.P.E. International, Inc.       Rig reporting software            Not applicable

       5/1998   New Prospect Drilling Company      6 land drilling rigs              Arkansas, Oklahoma

       5/1998   Can-Tex Drilling & Exploration,    7 land drilling rigs              Alberta, Canada
                Ltd.

       6/1998   Transocean-Nabors Drilling         Joint interest in a coiled        Alaska
                Technology LLC                     tubing drilling rig; certain
                                                   technology rights

       4/1999   Bayard Drilling Technologies,      87 land drilling rigs (73         Oklahoma, Texas, Louisiana,
                Inc.                               actively marketed); significant   Arkansas
                                                   inventories of new component
                                                   equipment (e.g., drill pipe,
                                                   engines and mud pumps);
                                                   oilfield hauling equipment fleet

      11/1999   Pool Energy Services Co.           790 land well                     U.S. Lower 48, Gulf of Mexico,
                                                   servicing/workover rigs (470      Alaska, International
                                                   actively marketed); 34 land
                                                   drilling rigs; 25 offshore
                                                   rigs; 300+ fluid handling
                                                   trucks; 1,060 storage tanks
                                                   and 15 salt-water disposal
                                                   wells; 27 offshore supply
                                                   vessels

    12/1999 -   Various                            7 offshore supply vessels         Gulf of Mexico
      10/2000                                      (including 5 new-builds)

      12/2000   Parker Drilling Company            1 arctic land rig; 1 ball mill    Alaska
                                                   unit

      11/2001   Command Drilling Corporation       15 land drilling rigs (plus one   Canada
                                                   under construction)

      4/2001,   Arabian Jack-up Partnership        Four jack-up rigs                 International
      6/2001,   1996, Ltd.; Santa Fe
   2/2002 and   International Corporation;
       6/2002   Transocean, Inc.

      3/18/02   Enserco Energy Service Inc.        30 drilling rigs, 209 workover    Canada
                                                   rigs

     10/09/02   Ryan Energy Technologies Inc.      Directional Drilling and          Canada, U.S. Lower 48,
                                                   MWD/LWD Assets                    Venezuela
</Table>



                                       20
<PAGE>


         (1) With the exception of the MND Drilling, Samson Rig Company and
jack-up rig transactions, all acquisitions of rigs also included substantial
quantities of drill collars and drill pipe.

         (2) Sold in January 1998.

Although Nabors continues to examine opportunities, there can be no assurance
that attractive rigs or other acquisition opportunities will continue to be
available, that the pricing will be economical or that we will be successful in
making such acquisitions in the future.

From time to time, we may sell a subsidiary or group of assets outside of our
core markets or business, if it is economically advantageous for us to do so.


VIII.    ENVIRONMENTAL COMPLIANCE.

Nabors does not presently anticipate that compliance with currently applicable
environmental regulations and controls will significantly change its competitive
position, capital spending or earnings during 2004. Nabors has been a party to
administrative and legal proceedings with governmental agencies that have arisen
under statutory provisions regulating the discharge or potential discharge of
material into the environment. Nabors believes it is in material compliance with
applicable environmental rules and regulations, and the cost of such compliance
is not material to the business or financial condition of Nabors. For a more
detailed description of the environmental laws and regulations applicable to
Nabors operations, see above under Risk Factors -- Noncompliance with
governmental regulation or exposure to environmental liabilities could adversely
affect Nabors' results of operations.


IX.      AVAILABLE INFORMATION.

Our internet address is www.nabors.com. We make available free of charge through
our website our annual report 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 Exchange Act as soon as reasonably
practicable after we electronically file such material with, or furnish it to,
the Securities and Exchange Commission.


ITEM 2.  PROPERTIES

Information regarding Nabors' rig fleet can be found on pages 35 through 37 of
our 2003 Annual Report and is incorporated into this document by reference.

Many of the international drilling rigs and certain of the Alaska rigs in our
fleet are supported by mobile camps which house the drilling crews and a
significant inventory of spare parts and supplies. In addition, we own various
trucks, forklifts, cranes, earth moving and other construction and
transportation equipment, which are used to support the drilling and logistics
operations.

Nabors and its subsidiaries own or lease executive and administrative office
space in St. Michael, Barbados (principal executive office); Houston, Texas;
Anchorage, Alaska; Harvey, Houma, Iberia, and New Iberia, Louisiana;
Bakersfield, California; Magnolia, Texas; Calgary and Nisku, Alberta, Canada;
Sana'a, Yemen; Dubai, U.A.E.; Dhahran, Saudi Arabia; and Anaco, Venezuela. We
also own or lease a number of facilities and storage yards used in support of
operations in each of our geographic markets.

Nabors and its subsidiaries own certain mineral interests in connection with
their investing and operating activities. Nabors does not consider these
properties to be material to its overall operations.



                                       21
<PAGE>


Additional information about our properties can be found in Notes 2 and 5 (each,
under the caption "Property, Plant and Equipment") and 13 (under the caption
"Operating Leases") of the Notes to Consolidated Financial Statements on pages
76 through 77, 84 and 95 through 96, respectively, of our 2003 Annual Report and
is incorporated into this document by reference. The revenues and property,
plant and equipment by geographic area for the fiscal years ended December 31,
2001, 2002 and 2003, can be found in Note 17 of the Notes to Consolidated
Financial Statements in the table on page 102 of our 2003 Annual Report, and are
incorporated into this document by reference.

Nabors' management believes that our equipment and facilities are adequate to
support our current level of operations as well as an expansion of drilling
operations in those geographical areas where we may expand.

ITEM 3.  LEGAL PROCEEDINGS

Nabors and its subsidiaries are defendants or otherwise involved in a number of
lawsuits in the ordinary course of their business. In the opinion of management,
our ultimate liability with respect to these pending lawsuits is not expected to
have a significant or material adverse effect on our consolidated financial
position, results of operation or cash flows.

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

Not applicable.

                                     PART II

ITEM 5.           MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
                  MATTERS

I.       MARKET AND STOCK PRICES.

Our shares are traded on the American Stock Exchange under the symbol "NBR". At
December 31, 2003, there were approximately 2,241 shareholders of record. Nabors
does not pay dividends with respect to its common shares. (See discussion above
under "Part I - Item 1 - BUSINESS - RISK FACTORS") The composite quarterly high,
low and closing prices for our common shares for each fiscal quarter of 2003 and
2002 can be found under the caption "Corporate Information - Price of Common
Shares" on page 108 of our 2003 Annual Report and are incorporated by reference
into this document.

The Company maintains eleven different equity compensation plans: the 1993 Stock
Option Plan for Non-Employee Directors, 1996 Executive Officers Incentive Stock
Plan, 1996 Employee Stock Plan, 1996 Chairman's Executive Stock Plan, 1996
Executive Officers Stock Plan, 1997 Executive Officers Incentive Stock Plan,
1998 Employee Stock Plan, 1998 Chairman's Executive Stock Plan, 1999 Stock
Option Plan for Non-Employee Directors, 1999 Pool Employee/Director Option
Exchange Plan and 2003 Employee Stock Plan pursuant to which it may grant equity
awards to eligible persons from certain plans. The terms of the Company's Equity
Compensation Plans are described more fully below.



                                       22
<PAGE>
The following table gives information about these equity compensation plans as
of December 31, 2003:

<Table>
<Caption>
                                     (a)                           (b)                            (c)
                         --------------------------     -------------------------   -------------------------------
                                                                                     Number of securities remaining
                         Number of securities to be     Weighted-average exercise    available for future issuance
                           issued upon exercise of        price of outstanding      under equity compensation plans
                            outstanding options,         options, warrants and      (excluding securities reflected
    Plan category            warrants and rights                 rights                      in column (a))
----------------------   --------------------------     -------------------------   -------------------------------
<S>                      <C>                            <C>                         <C>
Equity compensation
plans approved by
security holders                  9,410,328                     $32.6463                       5,474,469 (1)

Equity compensation
plans not approved by
security holders (2)             15,543,421                     $27.2383                       2,716,613
                                 ----------                                                    ---------
Total                            24,953,749                                                    8,191,082
</Table>

     1    The 1996 Employee Stock Plan incorporates an evergreen formula
          pursuant to which on each January 1, the aggregate number of shares
          reserved for issuance under the 1996 Employee Stock Plan will increase
          by an amount equal to 1 1/2 % of the shares of common stock
          outstanding on December 31 of the immediately preceding fiscal year.

     2    The Company issued 153,519 stock options under the 1999 Pool
          Employee/Director Option Exchange Plan of Pool Energy Services Co. The
          remaining options are exercisable for 10,392 common shares of the
          Company (after giving effect to the exchange ratio provided in the
          Pool acquisition agreement). The options have a weighted-average
          exercise price of $17.3823 per share. No further awards will be made
          under the 1999 Pool Employee/Director Option Exchange Plan.

Following is a brief summary of the material terms of the plans that have not
been approved by our shareholders.

1996 EXECUTIVE OFFICERS INCENTIVE STOCK PLAN

In October 1996 the Board adopted the 1996 Executive Officers Incentive Stock
Plan which has not been approved by shareholders.

The 1996 Executive Officers Incentive Stock Plan reserves for issuance up to
3,600,000 common shares of the Company pursuant to the exercise of options
granted under the plan. The plan is administered by an independent committee
appointed by the Company's Board of Directors. Options may be granted under the
plan to executive officers of the Company. No optionee may receive grants in
excess of 50% of the total number of common shares authorized to be issued under
the plan. Options granted under the plan are nonstatutory options not intended
to qualify under Section 422 of the Internal Revenue Code of 1986, as amended
(NSOs).

The exercise price of options granted under the plan are set by the committee,
but shall be no less than 100% of the fair market value per common share on the
date of the grant of the option. The term of the NSO may not exceed ten years.
Unless otherwise determined by the committee in its discretion, an option may
not be exercised after the optionee has ceased to be in the employ of the
Company.

1996 CHAIRMAN'S EXECUTIVE STOCK PLAN

In December 1996 the Board adopted the 1996 Chairman's Executive Stock Plan
which has not been approved by shareholders.



                                       23
<PAGE>


The 1996 Chairman's Executive Stock Plan reserves for issuance up to 850,000
common shares of the Company pursuant to the exercise of options granted under
the plan. The plan is administered by an independent committee appointed by the
Company's Board of Directors. Options may be granted under the plan to the
Chairman of the Board of the Company. Options granted under the plan are NSOs.

The exercise price of options granted under the plan are set by the committee,
but shall be no less than 100% of the fair market value per common share on the
date of the grant of the option. The term of the NSO may not exceed ten years.

In the event of a termination of employment for any reason, except by the
Company for cause or by voluntary resignation by optionee, all unvested options
shall be immediately exercisable as of the date of his termination of his
employment.

1996 EXECUTIVE OFFICERS STOCK PLAN

In August 1997 the Board adopted the 1996 Executive Officers Stock Plan, which
has not been approved by shareholders.

The 1996 Executive Officers Stock Plan reserves for issuance up to 860,000
common shares of the Company pursuant to the exercise of options granted under
the plan. The plan is administered by an independent committee appointed by the
Company's Board of Directors. Options may be granted under the plan to executive
officers of the Company. No optionee may receive grants in excess of 50% of the
total number of common shares authorized to be issued under the Plan. Options
granted under the plan are NSOs.

The exercise price of options granted under the plan shall be set by the
committee, but shall be no less than the fair market value per share of common
stock on the date of the grant of the option. The term of the NSO may not exceed
ten years.

Unless otherwise determined by the committee in its discretion, an option may
not be exercised after the optionee has ceased to be in the employ of the
Company.

1997 EXECUTIVE OFFICERS INCENTIVE STOCK PLAN

In August 1997 the Board adopted the 1997 Executive Officers Incentive Stock
Plan, which has not been approved by shareholders.

The 1997 Executive Officers Incentive Stock Plan reserves for issuance up to
2,450,000 common shares of the Company pursuant to the exercise of options
granted under the plan. The plan is administered by an independent committee
appointed by the Company's Board of Directors. Options may be granted under the
plan to executive officers of the Company. No optionee may receive grants in
excess of 50% of the total number of common shares authorized to be issued under
the plan. Options granted under the plan are NSOs.

The exercise price of options granted under the plan shall be set by the
committee, but shall be no less than 100% of the fair market value per common
share on the date of the grant of the option. The term of the NSO may not exceed
ten years.

Unless otherwise determined by the committee in its discretion, an option may
not be exercised after the optionee has ceased to be in the employ of the
Company.

1998 EMPLOYEE STOCK PLAN

In March 1998 the Board adopted the 1998 Employee Stock Plan, which has not been
approved by shareholders. Amendments were approved by the Company's Board of
Directors on December 11, 1998.



                                       24
<PAGE>


The 1998 Employee Stock Plan reserves for issuance up to 17,500,000 common
shares of the Company pursuant to the exercise of options granted under the
plan. The plan is administered by an independent committee appointed by the
Company's Board of Directors. The persons who shall be eligible to participate
in the plan are employees and consultants of the company. Options granted to
employees may either be awards of stock, non-qualified stock options (NQSOs),
incentive stock options (ISOs) or stock appreciation rights (SARs).

The exercise price of NQSOs shall be no less than 100% of the fair market value
per share of common stock on the date of the grant of the option. As determined
by the committee, on the date of the grant, an optionee may reduce the option
exercise price by paying the Company in cash, shares, options, or the
equivalent, an amount equal to the difference between the exercise price and the
reduced exercise price of the option. The committee may specify a period for
exercise of an option which period shall be in no event more than ten years from
the date of grant. The committee shall establish performance goals for stock
awards in writing not later than the date required for compliance under IRC
Section 162(m) and the vesting of such stock shall be contingent upon the
attainment of such performance goals. Stock awards shall vest over a period
determined by the Committee, which period shall expire no later than January 18,
2006. The committee may grant ISOs of not less than 100% of the fair market
value per common share on the date of grant; except that in the event the
optionee owns on the date of grant, securities possessing more than 10% of the
total combined voting power of all classes of securities of the Company or of
any subsidiary of the Company, the price per share shall not be less than 110%
of the fair market value per common share on the date of the grant and such
option shall expire five years from the date such option is granted. SARs may be
granted in conjunction with all or part of any option granted under the plan, in
which case the exercise of the SAR shall require the cancellation of a
corresponding portion of the option and the exercise of the option will result
in cancellation of a corresponding portion of the SAR. In the case of a NQSO,
such rights may be granted either at or after the time of grant of such option.
In the case of an ISO, such rights may be granted only at the time of grant of
such option. A SAR may also be granted on a stand alone basis. The term of an
SAR shall be established by the committee. The exercise price of a SAR shall in
no event be less than 100% of the fair market value per common share on the date
of grant.

Unless otherwise determined by the committee, an option may not be exercised
after the optionee has ceased to be in the employ of the Company. The committee
shall have the authority to make provisions in its award and grant agreements to
address vesting and other issues arising in connection with a change of control.

1998 CHAIRMAN'S EXECUTIVE STOCK PLAN

In March 1998 the Board adopted the 1998 Chairman's Executive Stock Plan, which
has not been approved by shareholders.

The 1998 Chairman's Executive Stock Plan reserves for issuance up to 764,924
common shares of the Company pursuant to the exercise of options granted under
the plan. The plan is administered by an independent committee appointed by the
Company's Board of Directors. Options may be granted under the plan to the
Chairman of the Board of the Company. Options granted under the plan are NSOs.

The exercise price of options granted under the plan shall be set by the
committee, but shall be no less than 100% of the fair market value per common
share on the date of the grant of the option. The term of the NSO may not exceed
ten years.

In the event of a termination of employment for any reason, except by the
Company for cause or by voluntary resignation by optionee, all unvested options
shall be immediately exercisable as of the date of his termination of his
employment.

1999 STOCK OPTION PLAN FOR NON-EMPLOYEE DIRECTORS

In December 1998 the Executive Committee of the Board adopted the 1999 Stock
Option Plan for Non-Employee Directors, which has not been approved by
shareholders.



                                       25
<PAGE>


The 1999 Stock Option Plan for Non-Employee Directors reserves for issuance up
to 1,500,000 common shares of the Company pursuant to the exercise of options
granted under the plan. The plan is administered by the Company's Board of
Directors, provided that the Board may appoint a committee to administer the
plan. In no event shall an eligible director consider or vote on the
administration of this plan or serve as a member of the committee. Options may
be granted under the plan to non-employee directors of the Company. Options
granted under the plan are NSOs.

The exercise price of options granted under the plan shall not be less than 100%
of the fair market value per common share on the date of grant. The term of the
NSO may not exceed ten years.

Options shall vest and become non-forfeitable on the first year anniversary of
the day on which such option was granted, if the optionee has continued to serve
as a director until that day, unless otherwise provided. In the event of
termination of an optionee's service as a director by reason of voluntary
retirement, declining to stand for re-election or becoming a full time employee
of the Company or a subsidiary of the Company, all unvested options granted
pursuant to this Plan shall automatically expire and shall not be exercisable
and all options unexercised shall continue to be exercisable until the stated
expiration date of such options. In the event of death or disablement of an
optionee while the optionee is a director, the then-outstanding options of such
optionee shall be exercisable for two years from the date of the death or
disablement of the optionee or by his/her successors in interest. All unvested
options shall automatically vest and become non-forfeitable as of the date of
death or disablement and shall be exercisable for two years from the date of the
death of the optionee or until the stated grant expiration date, whichever is
earlier, by the optionee or by his/her successors in interest. In the event of
the termination of an optionee's service as a director by the Board of Directors
for cause or the failure of such director to be re-elected, the administrator of
the plan in its sole discretion can cancel the then-outstanding options of such
optionee, including those options which have vested and such options shall
automatically expire and become non-exercisable on the effective date of such
termination.

1999 POOL EMPLOYEE/DIRECTOR OPTION EXCHANGE PLAN

In November 1999 the Board adopted the 1999 Pool Employee/Director Option
Exchange Plan, which has not been approved by shareholders.

The 1999 Pool Employee/Director Option Exchange Plan reserves for issuance up to
1,466,010 common shares of the Company pursuant to the exercise of options
granted under the plan. The plan is administered by a committee appointed by the
Board of Directors of the Company. Options may be granted under the plan to
former employees and non-employee directors of Pool Energy Services Co. or its
subsidiaries who held options to purchase shares of Pool common stock pursuant
to certain stock option plans of Pool. Options granted under the plan are NSOs.

The exercise price of options granted under the plan shall equal the exercise
price per share of the corresponding Pool option, divided by 1.025 (rounding the
resulting exercise price up to the nearest whole cent). The term of an NSO may
not exceed ten years after the acquisition date of the merger.

The period for exercise of an option shall be the same as the period for
exercise of the corresponding Pool option. If an optionee has ceased to be in
the employ of the Company or its subsidiaries, any outstanding options, whether
or not vested, generally may not be exercised after the optionee's date of
termination and shall be forfeited; provided however, in its sole discretion the
committee may extend the time to exercise any option to a period ending on it
applicable expiration date. The committee, in its discretion, shall have the
authority to make provisions in its grant agreements to address vesting and
other issues arising in connection with a change of control.

II.      DIVIDEND POLICY.

Nabors has not declared or paid any cash dividends on its common stock since
1982. We do not intend to pay any cash dividends on our common shares for the
foreseeable future.



                                       26
<PAGE>


III.     SHAREHOLDER MATTERS.

Bermuda has exchange controls which apply to residents in respect of the
Bermudian dollar. As an exempt company, Nabors is considered to be nonresident
for such controls; consequently, there are no Bermuda governmental restrictions
on the Company's ability to make transfers and carry out transactions in all
other currencies, including currency of the United States.

There is no reciprocal tax treaty between Bermuda and the United States
regarding withholding taxes. Under existing Bermuda law, there is no Bermuda
income or withholding tax on dividends, if any, paid by Nabors to its
shareholders. Furthermore, no Bermuda tax or other levy is payable on the sale
or other transfer (including by gift or on the death of the shareholder) of
Nabors common shares (other than by shareholders resident in Bermuda).

ITEM 6.  SELECTED FINANCIAL DATA

The information called for by this item can be found under the caption "Selected
Financial Data" on pages 46 and 47 of our 2003 Annual Report and is incorporated
into this document by reference.

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

The information called for by this item can be found under the caption
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" on pages 48 through 67 of our 2003 Annual Report and is incorporated
into this document by reference.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information called for by this item can be found under the caption
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Quantitative and Qualitative Disclosures About Market Risk" on
pages 65 through 67 of our 2003 Annual Report and is incorporated into this
document by reference.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The consolidated financial statements and the notes thereto, together with the
report thereon of PricewaterhouseCoopers LLP, appear on pages 69 through 107 of
our 2003 Annual Report and are incorporated herein by reference. With the
exception of the specific information expressly incorporated into Items 1, 2, 3,
5, 6, 7, 7A, and 8 of this document, our 2003 Annual Report is not deemed to be
filed as part of this report.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures that are designed to
provide reasonable assurance that information required to be disclosed in our
reports filed under the Securities and Exchange Act of 1934, as amended, is
recorded, processed, summarized, and reported within the time periods specified
in the Commission's rules and forms. We have investments in certain
unconsolidated entities that we do not control or manage. As we do not control
or manage these entities, our disclosure controls and procedures with respect to
such entities are necessarily more limited than those we maintain with respect
to our consolidated subsidiaries.

We evaluated the effectiveness of the design and operation of our "disclosure
controls and procedures" (as defined in Rule 13a-15(e) of the Exchange Act)
under the supervision and with the participation of management, including our
Chairman and Chief Executive Officer and Chief Financial Officer, as of the end
of this period covered by this report. Based upon that evaluation, our Chairman
and Chief Executive Officer and Chief Financial Officer concluded that our
disclosure controls and procedures are effective in timely making known to them
material information relating to Nabors and its consolidated subsidiaries
required to be disclosed in our reports filed or



                                       27
<PAGE>


submitted under the Exchange Act. There has been no change in our internal
control over financial reporting during the quarter ended December 31, 2003 that
has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.



                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information called for by this item will be contained in the Nabors
Industries Ltd. definitive proxy statement to be distributed in connection with
its 2004 annual meeting of shareholders under the captions "Election of
Directors" and "Other Executive Officers" and is incorporated into this document
by reference.

Section 16(a) Beneficial Ownership Reporting Compliance. Section 16(a) of the
Securities Exchange Act of 1934 requires Nabors' directors and executive
officers, and persons who own more than 10% of a registered class of Nabors'
equity securities, to file with the Securities and Exchange Commission and the
American Stock Exchange initial reports of ownership and reports of changes in
ownership of common shares and other equity securities of Nabors. Officers,
directors and greater than 10% shareholders are required by Commission
regulation to furnish Nabors with copies of all Section 16(a) forms which they
file.

To our knowledge, based solely on review of the copies of Forms 3 and 4 and
amendments thereto furnished to us during 2003 and Form 5 and amendments thereto
furnished to us with respect to the year 2003, and written representations that
no other reports were required, all Section 16(a) filings required to be made by
Nabors' officers, directors and greater than 10% beneficial owners with respect
to the fiscal year 2003 were timely filed, except that Mr. Martin Whitman filed
one Form 4 late with respect to a single purchase transaction that occurred in
September 2003.

ITEM 11. EXECUTIVE COMPENSATION

Except as specified in the following sentence, the information called for by
this item will be contained in our definitive proxy statement to be distributed
in connection with our 2004 annual meeting of shareholders under the caption
"Management Compensation" and is incorporated into this document by reference.
Information in Nabors' 2004 proxy statement not deemed to be "soliciting
material" or "filed" with the Commission under its rules, including the Report
of the Compensation Committee on Executive Compensation, the Report of the Audit
Committee and the Five Year Stock Performance Graph, is not deemed to be
incorporated by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
         RELATED STOCKHOLDER MATTERS

The information called for by this item will be contained in Nabors' 2004 proxy
statement under the caption "Share Ownership of Management and Principal
Shareholders" and is incorporated into this document by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information called for by this item will be contained in Nabors' 2004 proxy
statement under the captions "Certain Relationships" and "Compensation Committee
Interlocks and Insider Participation" and is incorporated into this document by
reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information called for by this item will be contained in Nabors' 2004 Proxy
Statement under the caption "Principal Accountant Fees and Services" and is
incorporated into this document by reference.



                                       28
<PAGE>


                                     PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a)      The following documents are filed as part of this report:

         (1)      The consolidated financial statements of Nabors Industries
                  Ltd. and subsidiaries, and notes thereto, are incorporated
                  herein by reference from our 2003 Annual Report commencing
                  from the respective page numbers indicated:

<Table>
<Caption>
                                                                                                      Page No.
                                                                                                      --------
<S>                                                                                                   <C>
                  Report of Independent Auditors........................................................  68
                  Consolidated Balance Sheets...........................................................  69
                  Consolidated Statements of Income.....................................................  70
                  Consolidated Statements of Cash Flows.................................................  71
                  Consolidated Statements of Changes in Stockholders' Equity............................  72
                  Notes to Consolidated Financial Statements............................................  75
</Table>

         (2)      Financial Statement Schedules

<Table>
<Caption>
                                                                                                      Page No.
                                                                                                      --------
<S>                                                                                                   <C>

                  Report of Independent Auditors on Financial Statement Schedule........................ S-1
                  Schedule II - Valuation and Qualifying Accounts....................................... S-2
</Table>

                  All other supplemental schedules are omitted because of the
                  absence of the conditions under which they are required or
                  because the required information is included in the financial
                  statements or related notes.

(b)      Reports on Form 8-K:

         The following Current Reports on Form 8-K were filed during the fourth
quarter of 2003.

         o        Report on Form 8-K filed with the Securities and Exchange
                  Commission (the "Commission") on October 29, 2003 with respect
                  to our third quarter 2003 earnings release.

         o        Report on Form 8-K filed with the Commission on October 10,
                  2003 with respect to our drilling venture with El Paso
                  Corporation.



                                       29
<PAGE>


(c)      Exhibits

<Table>
<Caption>
         Exhibit No.       Description
         -----------       -----------
<S>                        <C>
         2.1               Agreement and Plan of Merger among Nabors Industries,
                           Inc., Nabors Acquisition Corp. VIII, Nabors
                           Industries Ltd. and Nabors US Holdings Inc.
                           (incorporated by reference to Annex I to the proxy
                           statement/prospectus included in Nabors Industries
                           Ltd.'s Registration Statement on Form S-4 (File No.
                           333-76198) filed with the Commission on May 10, 2002,
                           as amended).

         2.2               Amended and Restated Acquisition Agreement, dated as
                           of March 18, 2002, by and between Nabors Industries,
                           Inc. and Enserco Energy Service Company Inc.
                           (incorporated by reference to Exhibit 2.1 to Nabors
                           Industries, Inc. Registration Statement on Form S-3
                           (File No. 333-85228)).

         2.3               Form of Plan of Arrangement Under Section 192 of the
                           Canada Business Corporations Act Involving and
                           Affecting Enserco Energy Service Company Inc. and its
                           Securityholders (included in Schedule B to Exhibit
                           2.2).

         2.4               Arrangement Agreement dated August 12, 2002 between
                           Nabors Industries Ltd. and Ryan Energy Technologies
                           Inc. (incorporated by reference to Exhibit 2.4 to
                           Nabors Industries Ltd.'s Form 10-K for the year ended
                           December 31, 2002 (File No. 000-49887)).

         3.1               Memorandum of Association of Nabors Industries Ltd.
                           (incorporated by reference to Annex II to the proxy
                           statement/prospectus included in Nabors Industries
                           Ltd.'s Registration Statement on Form S-4
                           (Registration No. 333-76198) filed with the
                           Commission on May 10, 2002, as amended).

         3.2               Amended and Restated Bye-Laws of Nabors Industries
                           Ltd. (incorporated by reference to Annex III to the
                           proxy statement/prospectus included in Nabors
                           Industries Ltd.'s Registration Statement on Form S-4
                           (Registration No. 333-76198) filed with the
                           Commission on May 10, 2002, as amended).

         3.3               Form of Resolutions of the Board of Directors of
                           Nabors Industries Ltd. authorizing the issue of the
                           Special Voting Preferred Share (incorporated by
                           reference to Exhibit 3.3 to Nabors Industries Ltd.'s
                           Post-Effective Amendment No. 1 to Registration
                           Statement on Form S-3 (Registration No. 333-85228-99)
                           filed with the Commission on June 11, 2002).

         4.1               Form of Senior Indenture of Nabors Industries Ltd.
                           (incorporated by reference to Exhibit 4.1 to Nabors
                           Industries Ltd.'s Registration Statement on Form S-3
                           (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.2               Form of Subordinated Indenture of Nabors Industries
                           Ltd. (incorporated by reference to Exhibit 4.2 to
                           Nabors Industries Ltd.'s Registration Statement on
                           Form S-3 (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.3               Form of Senior Debt Security of Nabors Industries
                           Ltd. and Form of Senior Guarantee by Nabors
                           Industries, Inc. (included in Exhibit 4.1).

         4.4               Form of Subordinated Debt Security of Nabors
                           Industries Ltd. and Form of Subordinated Guarantee by
                           Nabors Industries, Inc. (included in Exhibit 4.2).
</Table>



                                       30
<PAGE>


<Table>
<S>                        <C>
         4.5               Form of Senior Indenture of Nabors Industries, Inc.
                           (incorporated by reference to Exhibit 4.5 to Nabors
                           Industries Ltd.'s Registration Statement on Form S-3
                           (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.6               Form of Subordinated Indenture of Nabors Industries,
                           Inc. (incorporated by reference to Exhibit 4.6 to
                           Nabors Industries Ltd.'s Registration Statement on
                           Form S-3 (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.7               Form of Senior Debt Security of Nabors Industries,
                           Inc. and Form of Senior Guarantee by Nabors
                           Industries Ltd. (included in Exhibit 4.5).

         4.8               Form of Subordinated Debt Security of Nabors
                           Industries, Inc. and Form of Subordinated Guarantee
                           by Nabors Industries Ltd. (included in Exhibit 4.6).

         4.9               Form of Senior Indenture of Nabors International
                           Finance Inc. (incorporated by reference to Exhibit
                           4.9 to Nabors Industries Ltd.'s Registration
                           Statement on Form S-3 (Registration No. 333-102246)
                           filed with the Commission on December 30, 2002).

         4.10              Form of Subordinated Indenture of Nabors
                           International Finance Inc. (incorporated by reference
                           to Exhibit 4.10 to Nabors Industries Ltd.'s
                           Registration Statement on Form S-3 (Registration No.
                           333-102246) filed with the Commission on December 30,
                           2002).

         4.11              Form of Senior Debt Security of Nabors International
                           Finance Inc. and Form of Senior Guarantee by Nabors
                           Industries Ltd. and Nabors Industries, Inc. (included
                           in Exhibit 4.9).

         4.12              Form of Subordinated Debt Security of Nabors
                           International Finance Inc. and Form of Subordinated
                           Guarantee by Nabors Industries Ltd. and Nabors
                           Industries, Inc. (included in Exhibit 4.10).

         4.13              Form of Senior Indenture of Nabors Holdings Ltd.
                           (incorporated by reference to Exhibit 4.13 to Nabors
                           Industries Ltd.'s Registration Statement on Form S-3
                           (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.14              Form of Subordinated Indenture of Nabors Holdings
                           Ltd. (incorporated by reference to Exhibit 4.14 to
                           Nabors Industries Ltd.'s Registration Statement on
                           Form S-3 (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.15              Form of Senior Debt Security of Nabors Holdings Ltd.
                           and Form of Senior Guarantee by Nabors Industries
                           Ltd. and Nabors Industries, Inc. (included in Exhibit
                           4.13).

         4.16              Form of Subordinated Debt Security of Nabors Holdings
                           Ltd. and Form of Subordinated Guarantee by Nabors
                           Industries Ltd. and Nabors Industries, Inc. (included
                           in Exhibit 4.14).

         4.17              Form of Senior Indenture of Nabors Holdings 1, ULC.
                           (incorporated by reference to Exhibit 4.17 to Nabors
                           Industries Ltd.'s Registration Statement on Form S-3
                           (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.18              Form of Subordinated Indenture of Nabors Holdings 1,
                           ULC. (incorporated by reference to Exhibit 4.18 to
                           Nabors Industries Ltd.'s Registration Statement on
                           Form S-3 (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.19              Form of Senior Debt Security of Nabors Holdings 1,
                           ULC and Form of Senior Guarantee by Nabors Industries
                           Ltd. and Nabors Industries, Inc. (included in Exhibit
                           4.17).
</Table>



                                       31
<PAGE>


<Table>
<S>                        <C>
         4.20              Form of Subordinated Debt Security of Nabors Holdings
                           1, ULC and Form of Subordinated Guarantee by Nabors
                           Industries Ltd. and Nabors Industries, Inc. (included
                           in Exhibit 4.18).

         4.21              Indenture dated as of March 1, 1999 between Nabors
                           Industries, Inc., as Issuer, and Norwest Bank
                           Minnesota, National Association, as trustee, in
                           connection with $325,000,000 aggregate principal
                           amount of 6.80% Notes due 2004 (incorporated by
                           reference to Exhibit 4.1 to Nabors Industries, Inc.'s
                           Post-Effective Amendment No. 1 to Registration
                           Statement on Form S-3, Registration No. 333-25233,
                           filed with the Commission on March 5, 1999).

         4.22              Supplemental Indenture No. 1 dated as of March 1,
                           1999 between Nabors Industries, Inc., as Issuer, and
                           Norwest Bank Minnesota, National Association, as
                           trustee, in connection with the 6.80% Notes
                           (incorporated by reference to Exhibit 4.2 to Nabors
                           Industries, Inc.'s Post-Effective Amendment No. 1 to
                           Registration Statement on Form S-3, Registration No.
                           333-25233, filed with the Commission on March 5,
                           1999).

         4.23              Supplemental Indenture No. 2, dated as of June 21,
                           2002, between Nabors Industries, Inc., Nabors
                           Industries Ltd. and Wells Fargo Bank Minnesota,
                           National Association, with respect to Nabors
                           Industries, Inc.'s 6.8% notes due 2004 (incorporated
                           by reference to Exhibit 4.7 to Nabors Industries
                           Ltd.'s Form 10-Q, File No. 000-49887, filed with the
                           Commission on August 14, 2002).

         4.24              Indenture dated as of February 5, 2001 between Nabors
                           Industries, Inc. and Bank One, N.A., as trustee, in
                           connection with $1,382,200,000 principal amount at
                           maturity of Zero Coupon Convertible Senior Debentures
                           due 2021 (incorporated by reference to Exhibit 4.11
                           to Form 10-K, File No. 1-9245, filed with the
                           Commission on March 30, 2001).

         4.25              Form of Debenture (contained in Exhibit 4.24).

         4.26              First Supplemental Indenture, dated as of June 21,
                           2002 among Nabors Industries, Inc., as issuer, Nabors
                           Industries Ltd. as guarantor, and Bank One, N.A. as
                           trustee, with respect to Nabors Industries, Inc.'s
                           zero coupon convertible senior debentures due 2021
                           (incorporated by reference to Exhibit 4.5 to Nabors
                           Industries Ltd.'s Form 10-Q, File No. 000-49887,
                           filed with the Commission on August 14, 2002).

         4.27              Registration Rights Agreement dated as of January 31,
                           2000 between Nabors Industries, Inc. and the initial
                           purchaser of the Zero Coupon Convertible Senior
                           Debentures due 2021 (incorporated by reference to
                           Exhibit 4.13 to Form 10-K, File No. 1-9245, filed
                           with the Commission on March 30, 2001).

         4.28              Indenture, dated August 22, 2002, among Nabors
                           Industries, Inc., as issuer, Nabors Industries Ltd.,
                           as guarantor, and Bank One, N.A., with respect to
                           Nabors Industries, Inc.'s Series A and Series B
                           5.375% Senior Notes due 2012 (incorporated by
                           reference to Exhibit 4.1 to Nabors Industries, Inc.'s
                           Registration Statement on Form S-4 (Registration No.
                           333-10049201) filed with the Commission on October
                           11, 2002).

         4.29              Registration Rights Agreement, dated August 22, 2002,
                           among Nabors Industries, Inc., Nabors Industries
                           Ltd., and Lehman Brothers Inc. (incorporated by
                           reference to Exhibit 4.2 to Nabors Industries, Inc.'s
                           Registration Statement on Form S-4 (Registration No.
                           333-10049201) filed with the Commission on October
                           11, 2002).

         4.30              Form of 5.375% Senior Exchange Note due 2012
                           (included in Exhibit 4.29).
</Table>



                                       32
<PAGE>


<Table>
<S>                        <C>
         4.31              Indenture, dated August 22, 2002, among Nabors
                           Holdings 1, ULC, as issuer, Nabors Industries, Inc.
                           and Nabors Industries Ltd., as guarantors, and Bank
                           One, N.A., with respect to Nabors Holdings 1, ULC's
                           Series A and Series B 4.875% Senior Notes due 2009
                           (incorporated by reference to Exhibit 4.1 to Nabors
                           Holdings 1, ULC's Registration Statement on Form S-4
                           (Registration No. 333-10049301) filed with the
                           Commission on October 11, 2002).

         4.32              Registration Rights Agreement, dated August 22, 2002,
                           among Nabors Holdings 1, ULC, Nabors Industries,
                           Inc., Nabors Industries Ltd., and Lehman Brothers
                           Inc. (incorporated by reference to Exhibit 4.2 to
                           Nabors Holdings 1, ULC's Registration Statement on
                           Form S-4 (Registration No. 333-10049301) filed with
                           the Commission on October 11, 2002).

         4.33              Form of 4.875% Senior Exchange Note due 2009
                           (included in Exhibit 4.32).

         4.34              Form of Provisions Attaching to the Exchangeable
                           Shares of Nabors Exchangeco (Canada) Inc.
                           (incorporated by reference to Exhibit 4.1 to Nabors
                           Industries, Inc.'s Registration Statement on Form S-3
                           (Registration No. 333-85228) filed with the
                           Commission on March 29, 2002, as amended).

         4.35              Form of Support Agreement between Nabors Industries,
                           Inc., 3064297 Nova Scotia Company and Nabors
                           Exchangeco (Canada) Inc. (incorporated by reference
                           to Exhibit 4.2 to Nabors Industries, Inc.'s
                           Registration Statement on Form S-3 (Registration No.
                           333-85228) filed with the Commission on March 29,
                           2002, as amended).

         4.36              Form of Acknowledgement of Novation to Nabors
                           Industries, Inc., Nabors Exchangeco (Canada) Inc.,
                           Computershare Trust Company of Canada and 3064297
                           Nova Scotia Company executed by Nabors Industries
                           Ltd. (incorporated by reference to Exhibit 4.3 to
                           Nabors Industries Ltd.'s Post-Effective Amendment No.
                           1 to Registration Statement on Form S-3 (Registration
                           No. 333-85228-99) filed with the Commission on June
                           11, 2002).

         4.37              Indenture, dated as of June 10, 2003, between Nabors
                           Industries, Inc., Nabors Industries Ltd. and Bank
                           One, N.A. with respect to Nabors Industries, Inc.'s
                           Zero Coupon Senior Exchangeable Notes due 2023
                           (incorporated by reference to Exhibit 4.1 to Nabors
                           Delaware's and Nabors' Registration Statement on Form
                           S-3, (File No. 333-107806-01, filed with the
                           Commission of August 8, 2003)).

         4.38              Registration Rights Agreement, dated as of June 10,
                           2003, by and among Nabors Industries, Inc., Nabors
                           Industries Ltd. and Citigroup Global Markets Inc.
                           (incorporated by reference to Exhibit 4.2 to Nabors
                           Delaware's and Nabors' Registration Statement on Form
                           S-3, File No. 333-107806-01, filed with the
                           Commission on August 8, 2003).

         4.39              Form of Zero Coupon Senior Exchangeable Notes Due
                           2023 (included in Exhibit 4.38).

         10.1 (+)          1996 Employee Stock Plan (incorporated by reference
                           to Nabors Industries Inc.'s Registration Statement on
                           Form S-8, Registration No. 333-11313, filed September
                           3, 1996).

         10.2 (+)          1994 Executive Stock Option Agreement effective
                           December 28, 1994 between Nabors Industries, Inc. and
                           Eugene M. Isenberg (incorporated by reference to
                           Exhibit 10.4 to Nabors Industries Inc.'s Form 10-K,
                           File No. 1-9245, filed December 30, 1996).

         10.3 (+)          1994 Executive Stock Option Agreement effective
                           December 28, 1994 between Nabors Industries, Inc. and
                           Anthony G. Petrello (incorporated by reference to
                           Exhibit 10.5 to Nabors Industries Inc.'s Form 10-K,
                           File No. 1-9245, filed December 30, 1996).
</Table>



                                       33
<PAGE>


<Table>
<S>                        <C>
         10.4 (+)          Employment Agreement effective October 1, 1996
                           between Nabors Industries, Inc. and Eugene M.
                           Isenberg (incorporated by reference to Exhibit 10.7
                           to Nabors Industries Inc.'s Form 10-Q, File No.
                           1-9245, filed May 16, 1997).

         10.5 (+)          First Amendment to Amended and Restated Employment
                           Agreement between Nabors Industries, Inc., Nabors
                           Industries Ltd. and Eugene M. Isenberg dated as of
                           June 24, 2002 (incorporated by reference to Exhibit
                           10.1 to Nabors Industries Ltd.'s Form 10-Q, File No.
                           000-49887, filed August 14, 2002).

         10.6 (+)          Second Amendment to Employment Agreement between
                           Nabors Industries, Inc., Nabors Industries Ltd. and
                           Eugene M. Isenberg dated as of July 17, 2002
                           (incorporated by reference to Exhibit 10.1 to Nabors
                           Industries Ltd.'s Form 10-Q, File No. 000-49887,
                           filed August 14, 2002).

         10.7 (+)          Employment Agreement effective October 1, 1996
                           between Nabors Industries, Inc. and Anthony G.
                           Petrello (incorporated by reference to Exhibit 10.8
                           to Nabors Industries Inc.'s Form 10-Q, File No.
                           1-9245, filed May 16, 1997).

         10.8 (+)          First Amendment to Amended and Restated Employment
                           Agreement between Nabors Industries, Inc., Nabors
                           Industries Ltd. and Anthony G. Petrello dated as of
                           June 24, 2002 (incorporated by reference to Exhibit
                           10.2 to Nabors Industries Ltd.'s Form 10-Q, File No.
                           000-49887, filed August 14, 2002).

         10.9 (+)          Second Amendment to Employment Agreement between
                           Nabors Industries, Inc., Nabors Industries Ltd. and
                           Anthony G. Petrello dated as of July 17, 2002
                           (incorporated by reference to Exhibit 10.3 to Nabors
                           Industries Ltd.'s Form 10-Q, File No. 000-49887,
                           filed August 14, 2002).

         10.10 (+)         Waiver dated as of September 27, 2002 pursuant to
                           Section 9.[c] and Schedule 9.[c] of the Amended
                           Employment Agreement among Nabors Industries, Inc.,
                           Nabors Industries Ltd., and Anthony G. Petrello
                           (incorporated by reference to Exhibit 10.1 to Nabors
                           Industries Ltd.'s Form 10-Q, File No. 000-49887,
                           filed November 14, 2002).

         10.11 (+)         Nabors Industries, Inc. 1996 Chairman's Executive
                           Stock Plan (incorporated by reference to Exhibit
                           10.17 to Nabors Industries Inc.'s Form 10-K, File No.
                           1-9245, filed December 29, 1997).

         10.12 (+)         Nabors Industries, Inc. 1996 Executive Officers Stock
                           Plan (incorporated by reference to Exhibit 10.18 to
                           Nabors Industries Inc.'s Form 10-K, File No. 1-9245,
                           filed December 29, 1997).

         10.13 (+)         Nabors Industries, Inc. 1996 Executive Officers
                           Incentive Stock Plan (incorporated by reference to
                           Exhibit 10.9 to Nabors Industries Inc.'s Form 10-K,
                           File No. 1-9245, filed December 29, 1997).

         10.14 (+)         Nabors Industries, Inc. 1997 Executive Officers
                           Incentive Stock Plan (incorporated by reference to
                           Exhibit 10.20 to Nabors Industries Inc.'s Form 10-K,
                           File No. 1-9245, filed December 29, 1997).

         10.15 (+)         Nabors Industries, Inc. 1998 Employee Stock Plan
                           (incorporated by reference to Exhibit 10.19 to Nabors
                           Industries Inc.'s Form 10-K dated December 31, 1998,
                           File No. 1-9245, filed March 31, 1999).
</Table>



                                       34
<PAGE>


<Table>
<S>                        <C>
         10.16 (+)         Nabors Industries, Inc. 1998 Chairman's Executive
                           Stock Plan (incorporated by reference to Exhibit
                           10.20 to Nabors Industries Inc.'s Form 10-K dated
                           December 31, 1998, File No. 1-9245, filed March 31,
                           1999).

         10.17 (+)         Nabors Industries, Inc. 1999 Stock Option Plan for
                           Non-Employee Directors (incorporated by reference to
                           Exhibit 10.21 to Nabors Industries Inc.'s Form 10-K
                           dated December 31, 1998, File No. 1-9245, filed March
                           31, 1999).

         10.18 (+)         Amendment to Nabors Industries, Inc. 1999 Stock
                           Option Plan for Non-Employee Directors (incorporated
                           by reference to Exhibit 10.19 to Nabors Industries
                           Inc.'s Form 10-K, File No. 1-09245, filed March 19,
                           2002).

         10.19 (+)         1999 Pool Employee/Director Option Exchange Plan
                           (incorporated by reference to Exhibit 10.20 to Nabors
                           Industries Inc.'s Form 10-K, File No. 1-09245, filed
                           March 19, 2002).

         10.20             Form of Indemnification Agreement entered into
                           between Nabors Industries Ltd. and the directors and
                           executive officers identified in the schedule
                           thereto (incorporated by reference to Exhibit 10.28
                           to Nabors Industries Ltd.'s Form 10-K dated
                           December 31, 2002, File No. 000-49887, filed
                           March 31, 2003).

         10.21 (+)         Amended and Restated 1999 Stock Option Plan for
                           Non-Employee Directors (amended on May 2, 2003)
                           (incorporated by reference to Exhibit 10.29 to Nabors
                           Industries Ltd. 10-Q, File No. 000-49887, filed
                           May 12, 2003).

         10.22 (+)         2003 Employee Stock Option Plan (incorporated by
                           reference to Annex D of Nabors Notice of 2003 Annual
                           General Meeting of Shareholders and Proxy Statement,
                           File No. 000-49887, filed May 8, 2003).

         10.23             Purchase and Sale Agreement (Red River) by and among
                           El Paso Production Company and El Paso Production GOM
                           Inc., jointly and severally as Seller and Ramshorn
                           Investments, Inc., as Purchaser dated October 8,
                           2003.

         10.24             Purchase and Sale Agreement (USA) between El Paso
                           Production Oil & Gas USA, L.P., as Seller and
                           Ramshorn Investments, Inc., as Purchaser dated
                           October 8, 2003.

         10.25             Exploration Participation Agreement (South Texas) by
                           and between El Paso Production Oil & Gas Company and
                           El Paso Production Oil & Gas USA, L.P., jointly and
                           severally and Ramshorn Investments, Inc., dated
                           November 6, 2003.

         10.26             Exploration Participation Agreement (Catapult) by and
                           between El Paso Production Company, and Ramshorn
                           Investments, Inc., dated November 6, 2003.

         12                Computation of Ratios.

         13(1)             2003 Annual Report of Nabors Industries Ltd.

         14                Code of Ethics (Code of Business Conduct).

         21                Significant Subsidiaries of Nabors Industries Ltd.

         23                Consent of Independent Accountants.

         31.1              Rule 13a-14(a)/15d-14(a) Certification, executed by
                           Eugene M. Isenberg, Chairman and Chief Executive
                           Officer of Nabors Industries Ltd.
</Table>



                                       35
<PAGE>


<Table>
<S>                        <C>
         31.2              Rule 13a-14(a)/15d-14(a) Certification, executed by
                           Bruce P. Koch, Vice President and Chief Financial
                           Officer of Nabors Industries Ltd.

         32.1              Certifications required by Rule 13a-14(b) or Rule
                           15d-14(b) and Section 1350 of Chapter 63 of Title 18
                           of the United States Code (18 U.S.C. 1350), executed
                           by Eugene M. Isenberg, Chairman and Chief Executive
                           Officer of Nabors Industries Ltd. and Bruce P. Koch,
                           Vice President and Chief Financial Officer of Nabors
                           Industries Ltd.
</Table>

----------

(1)      With the exception of the specific information expressly incorporated
         into Items 1, 2, 3, 5, 6, 7, 7A, 8 and 14 of this document, the 2003
         Annual Report is not deemed to be filed as part of this report.

(+)      Management contract or compensatory plan or arrangement



                                       36
<PAGE>


                                   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.

                                                 NABORS INDUSTRIES LTD.


                                                 By:  /s/ Eugene M. Isenberg
                                                      --------------------------
                                                      Eugene M. Isenberg
                                                      Chairman and Chief
                                                      Executive Officer


                                                 By:  /s/ Bruce P. Koch
                                                      --------------------------
                                                      Bruce P. Koch
                                                      Vice President and Chief
                                                      Financial Officer
                                                      (Principal Financial and
                                                      Accounting Officer)

                                                 Date:  March 15, 2004

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.

<Table>
<Caption>
Signature                                                     Title                              Date
---------                                                     -----                              ----
<S>                                                  <C>                                     <C>
/s/ Eugene M. Isenberg                               Chairman and                            March 15, 2004
------------------------------------                 Chief Executive Officer
Eugene M. Isenberg

/s/ Anthony G. Petrello                              Deputy Chairman, President and          March 15, 2004
------------------------------------                 Chief Operating Officer
Anthony G. Petrello

/s/ James L. Payne                                   Director                                March 15, 2004
------------------------------------
James L. Payne

/s/ Hans Schmidt                                     Director                                March 15, 2004
------------------------------------
Hans Schmidt

/s/ Myron M. Sheinfeld                               Director                                March 15, 2004
------------------------------------
Myron M. Sheinfeld

/s/ Jack Wexler                                      Director                                March 15, 2004
------------------------------------
Jack Wexler

/s/ Martin J. Whitman                                Director                                March 15, 2004
------------------------------------
Martin J. Whitman
</Table>



                                       37
<PAGE>


                           GLOSSARY OF DRILLING TERMS


ABANDONMENT: To stop production of a well and plug the wellbore to prevent any
possible future leakage into fresh water.

BARGE RIG: A drilling rig that is placed on a towed barge for shallow inland
water, swamp and river applications.

BLOCK: Any assembly of pulleys on a common framework; in mechanics, one or more
pulleys mounted to rotate on a common axis. The crown block is an assembly of
pulleys mounted on beams at the top of the derrick or mast. The drilling line is
passed through the grooved wheel on the pulley of the crown block alternately
with the pulleys of the traveling block, which is raised and lowered in the
derrick or mast by the drilling line.

BLOWOUT: An uncontrolled expulsion of oil, natural gas or water (usually brine)
from a well into the atmosphere.

BLOWOUT PREVENTER (BOP): A stack of heavy-duty valves placed on top of the
casing to control well pressure during drilling.

BOTTOMHOLE PRESSURE: Pressure exerted upward by the reservoir formation.

CANTILEVER JACK-UPS: Jack-ups that have the derrick package mounted on steel
arms that can be extended out from the hull of the rig. Extension allows for the
positioning adjacent to a platform rig for development drilling.

CASED HOLE: A wellbore in which casing has been installed and cemented.

CASING: Steel pipe that is installed in the wellbore to protect from cave-in and
the migration of formation fluids into the wellbore, or communication between
zones.

CEMENTING: Filling the space between the casing and the wellbore walls with
cement to support the casing, and seal between zones.

CHRISTMAS TREE: An assembly of valves for flow control of production fluids or
gasses installed at the top of the casing.

COMPLETION: To finish a well and prepare it for production.

CONDUCTOR CASING OR CONDUCTOR PIPE: Wide-diameter casing installed at the
surface prior to rigging up to prevent caving.

CORING: Taking a sample of the formation or rock to determine its geologic
properties.

CROWN BLOCK: Stationary pulley system used to raise or lower drilling equipment
for the derrick. Supports the traveling block.

CRUDE OIL: Unrefined petroleum.

DAYRATE: The daily rate paid by an operator to a drilling contractor under a
daywork contract. (See also Footage and Turnkey Contract).

DAYWORK CONTRACT: A contract under which the drilling contractor is paid by the
day or portion thereof.



                                      A-1
<PAGE>


DERRICK: A steel mast used to support the drill string or drilling equipment
such as casing.

DRAWWORKS: Power equipment used for the hoisting of the drilling string via the
derrick. Consists of a spool wrapped with wire rope positioned to the side of
the derrick with wire traveling up the crown block.

DRILL BIT: A tool located at the end of the drill string used for cutting or
boring.

DRILL COLLARS: Heavy walled steel pipe added to the drill string between the
drill pipe and drill bit for additional downward pressure.

DRILL PIPE: Steel pipe used to conduct fluids and torque down to the drill bit.
Typically 30 feet in length.

DRILL STEM: All members in the assembly used for rotary drilling from the swivel
to the bit, including the kelly, the drill pipe and tool joints, the drill
collars, the stabilizers, and various specialty items.

DRILL STRING: An assembly consisting of drill pipe, drill collars and a drill
bit. The drill string serves as a conduit for fluid circulation and torque from
the power source.

DRY HOLE: An exploratory well that, although reaching target depths, does not
result in the production of hydrocarbons.

ELECTRIC RIG (SCR): A drilling rig that uses diesel generators to supply power
to separate electric motors to power each of the rig's components
(silicon-controlled rectifier).

EXPLORATORY WELL: A well drilled to either search for an undiscovered pool of
hydrocarbons or to define the limits of the hydrocarbon-bearing formation.

FIELD: An area representing a group of producing oil and/or natural gas wells.

FOOTAGE CONTRACTS: A contract under which the operator and contract driller
agree to a fixed price per foot drilled. Contractor carries more of the
operating risk than in a Daywork Contract (see also Daywork and Turnkey
Contract).

FORMATION: A strata of rock that is composed mainly of the same type of rock.

HOOK: A large, hook-shaped device from which the swivel is suspended. It is
designed to carry maximum loads ranging from 100 to 650 tons and turns on
bearings in its supporting housing.

HOOK LOAD: The weight of the drill stem that is suspended from the hook.

HORIZONTAL DRILLING: Deviation of the wellbore at least 80 degrees from vertical
so that the wellbore penetrates a productive formation in a manner parallel to
the formation.

HYDROCARBONS: Organic compounds of hydrogen and carbon atoms providing the basis
of all petroleum products. Hydrocarbons exist in a solid, liquid or gaseous
state.

INDEPENDENT LEG JACK-UPS: Jack-ups with open-truss steel legs with large steel
cylinders (spud cans) attached at the bottom for sea floor penetration and
stability.

JACK-UP RIG: Bottom supported offshore drilling rig consisting of a floating
platform that is towed on locations and jacked up above the water on three or
four legs. The platform supports the drilling derrick, equipment and crew
quarters. (See also independent leg, mat-supported, cantilever and slot
jack-ups.)

KELLY: A four- or six-sided pipe at the top of the drill string through which
rotation is parted.



                                      A-2
<PAGE>


KELLY BUSHING: A cage with V & square faced rollers which fits the kelly in
parting rotation while slowing up and down movement. The kelly pipe fits inside
the kelly bushing, which fits inside the master bushing, which fits inside the
rotary table. The rotary table creates the torque that is transmitted through
the kelly down the drill pipe to the drill bit (versus a top drive system which
foregoes all of such components).

LINER: A string of pipe used to case an open hole below an existing casing.

LOG: A recording of data.

MAT-SUPPORTED JACK-UPS: Jack-ups with cylindrical steel legs attached to a flat
base. Ideally suited for soft, muddy sea floors.

MECHANICAL RIG: A drilling rig where the power generated from combustion engines
(diesel) is distributed mechanically (shafts, sprockets, chains and clutches) to
the various components of the rig.

MUD: The liquid circulated through the wellbore during rotary drilling
operations. In addition to its function of bringing cuttings to the surface,
drilling mud cools and lubricates the drill bit and the drill stem, protects
against blowouts by holding back subsurface pressures, and deposits a mud cake
on the wall of the wellbore to prevent loss of fluids to the formation.

MUD LOGGING: The recording of information derived from examination and analysis
of formation cuttings made by the bit and of mud circulated out of the hole.

MUD PUMP: A large high-pressure pump used to circulate the mud on a drilling
rig.

MUD TANK: One of a series of open tanks, usually made of steel plate, through
which the drilling mud is cycled to remove sand and fine sediments. Also called
mud pits.

OPERATOR: Organization that obtains (buys or leases) the right to drill and
produce oil and/or natural gas from the owner of a specified location. The
operator of an oil or gas well or field.

OPERATOR - INDEPENDENT: A person or relatively small organization that engages
in the drilling, producing and selling of oil and gas, but has no pipeline or
other means of transportation or refining.

OPERATOR - INTEGRATED (MAJORS): A larger organization typically engaged in the
drilling, production, transportation and refining of oil and natural gas, as
well as the retail sales of oil and gas refined products.

OPERATOR - NATIONAL OIL COMPANY: State-owned organization typically engaged in
the drilling, production, transportation and refining of oil and natural gas, as
well as the retail sales of oil and gas refined products.

ORGANIZATION OF PETROLEUM EXPORTING COUNTRIES (OPEC): An organization formed in
1960 for the intent of negotiating the price and production levels of oil. There
are currently twelve members including Saudi Arabia, Kuwait, Iran, Qatar, United
Arab Emirates, Algeria, Libya, Nigeria, Venezuela, Indonesia, the Neutral Zone
(the area between Saudi Arabia and Kuwait) and Iraq.

PERMEABILITY: The measure of conductivity of fluids through the pores of rock.

PETROLEUM: A natural occurring solid, liquid or gaseous substance in the earth
containing hydrogen and carbon in various mixtures. Term often refers to oil and
does not include natural gas or gas liquids such as propane or butane.

PLATFORM: A drilling and production platform that is supported by a truss of
steel members (a jacket) secured to the ocean floor.



                                      A-3
<PAGE>


PLATFORM RIG: Mobile drilling rig packages mounted on production platforms.

PLUGGING A WELL: To stop the flow of hydrocarbons and/or water by filling the
wellbore with cement when the well is abandoned.

RESERVOIR: A porous, permeable, subsurface rock formation containing trapped
oil, natural gas, or water.

RIG: The derrick or mast, drawworks and attendant surface equipment of a
drilling unit.

RIG YEAR: A measure of the number of equivalent rigs operating during a given
period. It is calculated as the number of days rigs are operating divided by the
number of days in the period. For example, one rig operating 182.5 days during a
365-day period represents .5 rig years, and 100 rigs operating for 33,000
cumulative days, during a 365-day period would equal 90.4 rig years (33,000
divided by 365).

ROTARY DRILLING: A drilling method in which a hole is drilled by a rotating bit
to which a downward force is applied. The bit is fastened to and rotated by the
drill stem, which also provides a passageway through which the drilling fluid is
circulated.

SCR: See "Electric Rig".

SLOT JACK-UPS: Jack-ups that have the drilling derrick mounted over a slot in
the hull and cannot be used over adjacent structures.

SPUDDING THE WELL: The initiation of the drilling of a well.

STACK A RIG: To store a drilling rig on completion of a job when the rig is to
be withdrawn from operation for a time.

SWIVEL: A rotary tool that is hung from the rotary hook and the traveling block
to suspend the drill stem and to permit it to rotate freely. It also provides a
connection for the rotary hose and a passageway for the flow of drilling fluid
into the drill stem.

TOOL JOINTS: Heavy duty steel couplings used to connect lengths of drill pipe.

TOP DRIVE: A powered swivel connected directly into the drill stem to provide
the necessary torque for the drill bit. Replaces the conventional rotary table
and hangs from the hook attached to the traveling block. Allows three lengths of
drill pipe to be tripped in and out at a time, and provides makeup and breakup
power for the assembly of the drill pipe lengths as well. Generally considered
to save time over the rotary table assembly.

TORQUE: A force that causes or attempts to cause a rotation or torsion.

TRAVELING BLOCK: Block hanging from the derrick supporting the drill string as
it "travels" up and down as it raises and lowers the drill string into the
wellbore.

TRIP: When drill string is pulled and returned to the wellbore.

TURNKEY CONTRACT: A contract under which the drilling contractor agrees to drill
a well to the operator's specifications for a fixed lump sum fee. The contractor
carries the majority of the operating risk. (See also Dayrate and Footage
Contracts.)

UTILIZATION: A measure of the portion of the available rig or vessel fleet, as
applicable, in use during a given period. It is calculated as rig (or vessel)
years divided by total rigs (or vessels) available. For example, if the
equivalent rig (or vessel) years are 100 and the available fleet is 200, the
utilization rate is 50%.



                                      A-4
<PAGE>


VESSEL YEAR: A measure of the number of equivalent vessels operating during a
given period. It is calculated as the number of days vessels are operating
divided by the number of days in the period. For example, one vessel operating
182.5 days during a 365-day period represents .5 vessel years.

WELLBORE (WELL): The hole created when drilling that serves as the passageway
between the surface and the reservoir.

WELLHEAD: Flow control equipment located at the top of the casing string at the
surface of the wellbore.

WELL-SERVICING: Maintenance work on a producing well to improve its flow rate.
Service typically involves repairing equipment installed during drilling,
completion or workover, but may include addition of new equipment.
Well-servicing jobs usually take less than 48 hours to complete.

WILDCAT: An exploratory well drilled in an unknown or unproven area.

WORKOVER: Essentially, refurbishment of a well to improve its flow rate.
Workover includes any of several operations on a well to restore or increase
production when a reservoir stops producing at the rate it should. Many workover
jobs involve treating the reservoir rock, rather than the equipment in the well.
Workover jobs typically take a few days to several weeks to complete.



                                      A-5
<PAGE>


                        REPORT OF INDEPENDENT AUDITORS ON
                          FINANCIAL STATEMENT SCHEDULE

To the Board of Directors
of Nabors Industries Ltd.:

Our audits of the consolidated financial statements referred to in our report
dated March 5, 2004 appearing in the 2003 Annual Report to Shareholders of
Nabors Industries Ltd. (which report and consolidated financial statements are
incorporated by reference in this Annual Report on Form 10-K) also included an
audit of the financial statement schedule listed in Item 15(a)(2) of this Form
10-K. In our opinion, this financial statement schedule presents fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements.

/s/ PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 5, 2004



                                      S-1
<PAGE>
NABORS INDUSTRIES LTD.

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2003, 2002, and 2001


<Table>
<Caption>
                                        Balance at     Charged to     Charged to                           Balance at
                                        Beginning      Costs and        Other                                End of
(In Thousands)                          of Period       Expenses       Accounts         Deductions           Period
-----------------------------------     ----------     ----------     ----------        ----------         ----------
<S>                                     <C>            <C>            <C>               <C>                <C>
2003
    Allowance for doubtful accounts     $   13,801     $    1,311     $      178        $   (4,304)(1)     $   10,986
    Inventory reserve                        4,270            475             --            (3,378)(2)          1,367
    Valuation allowance on deferred
       tax assets                            6,540          5,163             --                --             11,703

2002
    Allowance for doubtful accounts     $   22,366     $    2,221     $    3,249(3)     $  (14,035)(4)     $   13,801
    Inventory reserve                        4,308            248             --              (286)(2)          4,270
    Valuation allowance on deferred
       tax assets                               --          6,540             --                --              6,540
2001
    Allowance for doubtful accounts     $    5,381     $   20,757     $       --        $   (3,772)(1)     $   22,366
    Inventory reserve                        5,595            527             --            (1,814)(2)          4,308
</Table>

(1)      Uncollected receivables written off, net of recoveries.

(2)      Inventory reserves written off.

(3)      Primarily related to acquisitions.

(4)      Includes uncollected receivables written off, net of recoveries, and
         $6.5 million related to receipt of amounts previously reserved for.



                                      S-2
<PAGE>
                               Index to Exhibits


<Table>
<Caption>
         Exhibit No.       Description
         -----------       -----------
<S>                        <C>
         2.1               Agreement and Plan of Merger among Nabors Industries,
                           Inc., Nabors Acquisition Corp. VIII, Nabors
                           Industries Ltd. and Nabors US Holdings Inc.
                           (incorporated by reference to Annex I to the proxy
                           statement/prospectus included in Nabors Industries
                           Ltd.'s Registration Statement on Form S-4 (File No.
                           333-76198) filed with the Commission on May 10, 2002,
                           as amended).

         2.2               Amended and Restated Acquisition Agreement, dated as
                           of March 18, 2002, by and between Nabors Industries,
                           Inc. and Enserco Energy Service Company Inc.
                           (incorporated by reference to Exhibit 2.1 to Nabors
                           Industries, Inc. Registration Statement on Form S-3
                           (File No. 333-85228)).

         2.3               Form of Plan of Arrangement Under Section 192 of the
                           Canada Business Corporations Act Involving and
                           Affecting Enserco Energy Service Company Inc. and its
                           Securityholders (included in Schedule B to Exhibit
                           2.2).

         2.4               Arrangement Agreement dated August 12, 2002 between
                           Nabors Industries Ltd. and Ryan Energy Technologies
                           Inc. (incorporated by reference to Exhibit 2.4 to
                           Nabors Industries Ltd.'s Form 10-K for the year ended
                           December 31, 2002 (File No. 000-49887)).

         3.1               Memorandum of Association of Nabors Industries Ltd.
                           (incorporated by reference to Annex II to the proxy
                           statement/prospectus included in Nabors Industries
                           Ltd.'s Registration Statement on Form S-4
                           (Registration No. 333-76198) filed with the
                           Commission on May 10, 2002, as amended).

         3.2               Amended and Restated Bye-Laws of Nabors Industries
                           Ltd. (incorporated by reference to Annex III to the
                           proxy statement/prospectus included in Nabors
                           Industries Ltd.'s Registration Statement on Form S-4
                           (Registration No. 333-76198) filed with the
                           Commission on May 10, 2002, as amended).

         3.3               Form of Resolutions of the Board of Directors of
                           Nabors Industries Ltd. authorizing the issue of the
                           Special Voting Preferred Share (incorporated by
                           reference to Exhibit 3.3 to Nabors Industries Ltd.'s
                           Post-Effective Amendment No. 1 to Registration
                           Statement on Form S-3 (Registration No. 333-85228-99)
                           filed with the Commission on June 11, 2002).

         4.1               Form of Senior Indenture of Nabors Industries Ltd.
                           (incorporated by reference to Exhibit 4.1 to Nabors
                           Industries Ltd.'s Registration Statement on Form S-3
                           (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.2               Form of Subordinated Indenture of Nabors Industries
                           Ltd. (incorporated by reference to Exhibit 4.2 to
                           Nabors Industries Ltd.'s Registration Statement on
                           Form S-3 (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.3               Form of Senior Debt Security of Nabors Industries
                           Ltd. and Form of Senior Guarantee by Nabors
                           Industries, Inc. (included in Exhibit 4.1).

         4.4               Form of Subordinated Debt Security of Nabors
                           Industries Ltd. and Form of Subordinated Guarantee by
                           Nabors Industries, Inc. (included in Exhibit 4.2).
</Table>



<PAGE>


<Table>
<S>                        <C>
         4.5               Form of Senior Indenture of Nabors Industries, Inc.
                           (incorporated by reference to Exhibit 4.5 to Nabors
                           Industries Ltd.'s Registration Statement on Form S-3
                           (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.6               Form of Subordinated Indenture of Nabors Industries,
                           Inc. (incorporated by reference to Exhibit 4.6 to
                           Nabors Industries Ltd.'s Registration Statement on
                           Form S-3 (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.7               Form of Senior Debt Security of Nabors Industries,
                           Inc. and Form of Senior Guarantee by Nabors
                           Industries Ltd. (included in Exhibit 4.5).

         4.8               Form of Subordinated Debt Security of Nabors
                           Industries, Inc. and Form of Subordinated Guarantee
                           by Nabors Industries Ltd. (included in Exhibit 4.6).

         4.9               Form of Senior Indenture of Nabors International
                           Finance Inc. (incorporated by reference to Exhibit
                           4.9 to Nabors Industries Ltd.'s Registration
                           Statement on Form S-3 (Registration No. 333-102246)
                           filed with the Commission on December 30, 2002).

         4.10              Form of Subordinated Indenture of Nabors
                           International Finance Inc. (incorporated by reference
                           to Exhibit 4.10 to Nabors Industries Ltd.'s
                           Registration Statement on Form S-3 (Registration No.
                           333-102246) filed with the Commission on December 30,
                           2002).

         4.11              Form of Senior Debt Security of Nabors International
                           Finance Inc. and Form of Senior Guarantee by Nabors
                           Industries Ltd. and Nabors Industries, Inc. (included
                           in Exhibit 4.9).

         4.12              Form of Subordinated Debt Security of Nabors
                           International Finance Inc. and Form of Subordinated
                           Guarantee by Nabors Industries Ltd. and Nabors
                           Industries, Inc. (included in Exhibit 4.10).

         4.13              Form of Senior Indenture of Nabors Holdings Ltd.
                           (incorporated by reference to Exhibit 4.13 to Nabors
                           Industries Ltd.'s Registration Statement on Form S-3
                           (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.14              Form of Subordinated Indenture of Nabors Holdings
                           Ltd. (incorporated by reference to Exhibit 4.14 to
                           Nabors Industries Ltd.'s Registration Statement on
                           Form S-3 (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.15              Form of Senior Debt Security of Nabors Holdings Ltd.
                           and Form of Senior Guarantee by Nabors Industries
                           Ltd. and Nabors Industries, Inc. (included in Exhibit
                           4.13).

         4.16              Form of Subordinated Debt Security of Nabors Holdings
                           Ltd. and Form of Subordinated Guarantee by Nabors
                           Industries Ltd. and Nabors Industries, Inc. (included
                           in Exhibit 4.14).

         4.17              Form of Senior Indenture of Nabors Holdings 1, ULC.
                           (incorporated by reference to Exhibit 4.17 to Nabors
                           Industries Ltd.'s Registration Statement on Form S-3
                           (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.18              Form of Subordinated Indenture of Nabors Holdings 1,
                           ULC. (incorporated by reference to Exhibit 4.18 to
                           Nabors Industries Ltd.'s Registration Statement on
                           Form S-3 (Registration No. 333-102246) filed with the
                           Commission on December 30, 2002).

         4.19              Form of Senior Debt Security of Nabors Holdings 1,
                           ULC and Form of Senior Guarantee by Nabors Industries
                           Ltd. and Nabors Industries, Inc. (included in Exhibit
                           4.17).
</Table>

<PAGE>


<Table>
<S>                        <C>
         4.20              Form of Subordinated Debt Security of Nabors Holdings
                           1, ULC and Form of Subordinated Guarantee by Nabors
                           Industries Ltd. and Nabors Industries, Inc. (included
                           in Exhibit 4.18).

         4.21              Indenture dated as of March 1, 1999 between Nabors
                           Industries, Inc., as Issuer, and Norwest Bank
                           Minnesota, National Association, as trustee, in
                           connection with $325,000,000 aggregate principal
                           amount of 6.80% Notes due 2004 (incorporated by
                           reference to Exhibit 4.1 to Nabors Industries, Inc.'s
                           Post-Effective Amendment No. 1 to Registration
                           Statement on Form S-3, Registration No. 333-25233,
                           filed with the Commission on March 5, 1999).

         4.22              Supplemental Indenture No. 1 dated as of March 1,
                           1999 between Nabors Industries, Inc., as Issuer, and
                           Norwest Bank Minnesota, National Association, as
                           trustee, in connection with the 6.80% Notes
                           (incorporated by reference to Exhibit 4.2 to Nabors
                           Industries, Inc.'s Post-Effective Amendment No. 1 to
                           Registration Statement on Form S-3, Registration No.
                           333-25233, filed with the Commission on March 5,
                           1999).

         4.23              Supplemental Indenture No. 2, dated as of June 21,
                           2002, between Nabors Industries, Inc., Nabors
                           Industries Ltd. and Wells Fargo Bank Minnesota,
                           National Association, with respect to Nabors
                           Industries, Inc.'s 6.8% notes due 2004 (incorporated
                           by reference to Exhibit 4.7 to Nabors Industries
                           Ltd.'s Form 10-Q, File No. 000-49887, filed with the
                           Commission on August 14, 2002).

         4.24              Indenture dated as of February 5, 2001 between Nabors
                           Industries, Inc. and Bank One, N.A., as trustee, in
                           connection with $1,382,200,000 principal amount at
                           maturity of Zero Coupon Convertible Senior Debentures
                           due 2021 (incorporated by reference to Exhibit 4.11
                           to Form 10-K, File No. 1-9245, filed with the
                           Commission on March 30, 2001).

         4.25              Form of Debenture (contained in Exhibit 4.24).

         4.26              First Supplemental Indenture, dated as of June 21,
                           2002 among Nabors Industries, Inc., as issuer, Nabors
                           Industries Ltd. as guarantor, and Bank One, N.A. as
                           trustee, with respect to Nabors Industries, Inc.'s
                           zero coupon convertible senior debentures due 2021
                           (incorporated by reference to Exhibit 4.5 to Nabors
                           Industries Ltd.'s Form 10-Q, File No. 000-49887,
                           filed with the Commission on August 14, 2002).

         4.27              Registration Rights Agreement dated as of January 31,
                           2000 between Nabors Industries, Inc. and the initial
                           purchaser of the Zero Coupon Convertible Senior
                           Debentures due 2021 (incorporated by reference to
                           Exhibit 4.13 to Form 10-K, File No. 1-9245, filed
                           with the Commission on March 30, 2001).

         4.28              Indenture, dated August 22, 2002, among Nabors
                           Industries, Inc., as issuer, Nabors Industries Ltd.,
                           as guarantor, and Bank One, N.A., with respect to
                           Nabors Industries, Inc.'s Series A and Series B
                           5.375% Senior Notes due 2012 (incorporated by
                           reference to Exhibit 4.1 to Nabors Industries, Inc.'s
                           Registration Statement on Form S-4 (Registration No.
                           333-10049201) filed with the Commission on October
                           11, 2002).

         4.29              Registration Rights Agreement, dated August 22, 2002,
                           among Nabors Industries, Inc., Nabors Industries
                           Ltd., and Lehman Brothers Inc. (incorporated by
                           reference to Exhibit 4.2 to Nabors Industries, Inc.'s
                           Registration Statement on Form S-4 (Registration No.
                           333-10049201) filed with the Commission on October
                           11, 2002).

         4.30              Form of 5.375% Senior Exchange Note due 2012
                           (included in Exhibit 4.29).
</Table>


<PAGE>


<Table>
<S>                        <C>
         4.31              Indenture, dated August 22, 2002, among Nabors
                           Holdings 1, ULC, as issuer, Nabors Industries, Inc.
                           and Nabors Industries Ltd., as guarantors, and Bank
                           One, N.A., with respect to Nabors Holdings 1, ULC's
                           Series A and Series B 4.875% Senior Notes due 2009
                           (incorporated by reference to Exhibit 4.1 to Nabors
                           Holdings 1, ULC's Registration Statement on Form S-4
                           (Registration No. 333-10049301) filed with the
                           Commission on October 11, 2002).

         4.32              Registration Rights Agreement, dated August 22, 2002,
                           among Nabors Holdings 1, ULC, Nabors Industries,
                           Inc., Nabors Industries Ltd., and Lehman Brothers
                           Inc. (incorporated by reference to Exhibit 4.2 to
                           Nabors Holdings 1, ULC's Registration Statement on
                           Form S-4 (Registration No. 333-10049301) filed with
                           the Commission on October 11, 2002).

         4.33              Form of 4.875% Senior Exchange Note due 2009
                           (included in Exhibit 4.32).

         4.34              Form of Provisions Attaching to the Exchangeable
                           Shares of Nabors Exchangeco (Canada) Inc.
                           (incorporated by reference to Exhibit 4.1 to Nabors
                           Industries, Inc.'s Registration Statement on Form S-3
                           (Registration No. 333-85228) filed with the
                           Commission on March 29, 2002, as amended).

         4.35              Form of Support Agreement between Nabors Industries,
                           Inc., 3064297 Nova Scotia Company and Nabors
                           Exchangeco (Canada) Inc. (incorporated by reference
                           to Exhibit 4.2 to Nabors Industries, Inc.'s
                           Registration Statement on Form S-3 (Registration No.
                           333-85228) filed with the Commission on March 29,
                           2002, as amended).

         4.36              Form of Acknowledgement of Novation to Nabors
                           Industries, Inc., Nabors Exchangeco (Canada) Inc.,
                           Computershare Trust Company of Canada and 3064297
                           Nova Scotia Company executed by Nabors Industries
                           Ltd. (incorporated by reference to Exhibit 4.3 to
                           Nabors Industries Ltd.'s Post-Effective Amendment No.
                           1 to Registration Statement on Form S-3 (Registration
                           No. 333-85228-99) filed with the Commission on June
                           11, 2002).

         4.37              Indenture, dated as of June 10, 2003, between Nabors
                           Industries, Inc., Nabors Industries Ltd. and Bank
                           One, N.A. with respect to Nabors Industries, Inc.'s
                           Zero Coupon Senior Exchangeable Notes due 2023
                           (incorporated by reference to Exhibit 4.1 to Nabors
                           Delaware's and Nabors' Registration Statement on Form
                           S-3, (File No. 333-107806-01, filed with the
                           Commission of August 8, 2003)).

         4.38              Registration Rights Agreement, dated as of June 10,
                           2003, by and among Nabors Industries, Inc., Nabors
                           Industries Ltd. and Citigroup Global Markets Inc.
                           (incorporated by reference to Exhibit 4.2 to Nabors
                           Delaware's and Nabors' Registration Statement on Form
                           S-3, File No. 333-107806-01, filed with the
                           Commission on August 8, 2003).

         4.39              Form of Zero Coupon Senior Exchangeable Notes Due
                           2023 (included in Exhibit 4.38.).

         10.1 (+)          1996 Employee Stock Plan (incorporated by reference
                           to Nabors Industries Inc.'s Registration Statement on
                           Form S-8, Registration No. 333-11313, filed September
                           3, 1996).

         10.2 (+)          1994 Executive Stock Option Agreement effective
                           December 28, 1994 between Nabors Industries, Inc. and
                           Eugene M. Isenberg (incorporated by reference to
                           Exhibit 10.4 to Nabors Industries Inc.'s Form 10-K,
                           File No. 1-9245, filed December 30, 1996).

         10.3 (+)          1994 Executive Stock Option Agreement effective
                           December 28, 1994 between Nabors Industries, Inc. and
                           Anthony G. Petrello (incorporated by reference to
                           Exhibit 10.5 to Nabors Industries Inc.'s Form 10-K,
                           File No. 1-9245, filed December 30, 1996).
</Table>



<PAGE>


<Table>
<S>                        <C>
         10.4 (+)          Employment Agreement effective October 1, 1996
                           between Nabors Industries, Inc. and Eugene M.
                           Isenberg (incorporated by reference to Exhibit 10.7
                           to Nabors Industries Inc.'s Form 10-Q, File No.
                           1-9245, filed May 16, 1997).

         10.5 (+)          First Amendment to Amended and Restated Employment
                           Agreement between Nabors Industries, Inc., Nabors
                           Industries Ltd. and Eugene M. Isenberg dated as of
                           June 24, 2002 (incorporated by reference to Exhibit
                           10.1 to Nabors Industries Ltd.'s Form 10-Q, File No.
                           000-49887, filed August 14, 2002).

         10.6 (+)          Second Amendment to Employment Agreement between
                           Nabors Industries, Inc., Nabors Industries Ltd. and
                           Eugene M. Isenberg dated as of July 17, 2002
                           (incorporated by reference to Exhibit 10.1 to Nabors
                           Industries Ltd.'s Form 10-Q, File No. 000-49887,
                           filed August 14, 2002).

         10.7 (+)          Employment Agreement effective October 1, 1996
                           between Nabors Industries, Inc. and Anthony G.
                           Petrello (incorporated by reference to Exhibit 10.8
                           to Nabors Industries Inc.'s Form 10-Q, File No.
                           1-9245, filed May 16, 1997).

         10.8 (+)          First Amendment to Amended and Restated Employment
                           Agreement between Nabors Industries, Inc., Nabors
                           Industries Ltd. and Anthony G. Petrello dated as of
                           June 24, 2002 (incorporated by reference to Exhibit
                           10.2 to Nabors Industries Ltd.'s Form 10-Q, File No.
                           000-49887, filed August 14, 2002).

         10.9 (+)          Second Amendment to Employment Agreement between
                           Nabors Industries, Inc., Nabors Industries Ltd. and
                           Anthony G. Petrello dated as of July 17, 2002
                           (incorporated by reference to Exhibit 10.3 to Nabors
                           Industries Ltd.'s Form 10-Q, File No. 000-49887,
                           filed August 14, 2002).

         10.10 (+)         Waiver dated as of September 27, 2002 pursuant to
                           Section 9.[c] and Schedule 9.[c] of the Amended
                           Employment Agreement among Nabors Industries, Inc.,
                           Nabors Industries Ltd., and Anthony G. Petrello
                           (incorporated by reference to Exhibit 10.1 to Nabors
                           Industries Ltd.'s Form 10-Q, File No. 000-49887,
                           filed November 14, 2002).

         10.11 (+)         Nabors Industries, Inc. 1996 Chairman's Executive
                           Stock Plan (incorporated by reference to Exhibit
                           10.17 to Nabors Industries Inc.'s Form 10-K, File No.
                           1-9245, filed December 29, 1997).

         10.12 (+)         Nabors Industries, Inc. 1996 Executive Officers Stock
                           Plan (incorporated by reference to Exhibit 10.18 to
                           Nabors Industries Inc.'s Form 10-K, File No. 1-9245,
                           filed December 29, 1997).

         10.13 (+)         Nabors Industries, Inc. 1996 Executive Officers
                           Incentive Stock Plan (incorporated by reference to
                           Exhibit 10.9 to Nabors Industries Inc.'s Form 10-K,
                           File No. 1-9245, filed December 29, 1997).

         10.14 (+)         Nabors Industries, Inc. 1997 Executive Officers
                           Incentive Stock Plan (incorporated by reference to
                           Exhibit 10.20 to Nabors Industries Inc.'s Form 10-K,
                           File No. 1-9245, filed December 29, 1997).

         10.15 (+)         Nabors Industries, Inc. 1998 Employee Stock Plan
                           (incorporated by reference to Exhibit 10.19 to Nabors
                           Industries Inc.'s Form 10-K dated December 31, 1998,
                           File No. 1-9245, filed March 31, 1999).
</Table>



<PAGE>


<Table>
<S>                        <C>
         10.16 (+)         Nabors Industries, Inc. 1998 Chairman's Executive
                           Stock Plan (incorporated by reference to Exhibit
                           10.20 to Nabors Industries Inc.'s Form 10-K dated
                           December 31, 1998, File No. 1-9245, filed March 31,
                           1999).

         10.17 (+)         Nabors Industries, Inc. 1999 Stock Option Plan for
                           Non-Employee Directors (incorporated by reference to
                           Exhibit 10.21 to Nabors Industries Inc.'s Form 10-K
                           dated December 31, 1998, File No. 1-9245, filed March
                           31, 1999).

         10.18 (+)         Amendment to Nabors Industries, Inc. 1999 Stock
                           Option Plan for Non-Employee Directors (incorporated
                           by reference to Exhibit 10.19 to Nabors Industries
                           Inc.'s Form 10-K, File No. 1-09245, filed March 19,
                           2002).

         10.19 (+)         1999 Pool Employee/Director Option Exchange Plan
                           (incorporated by reference to Exhibit 10.20 to Nabors
                           Industries Inc.'s Form 10-K, File No. 1-09245, filed
                           March 19, 2002).

         10.20             Form of Indemnification Agreement entered into
                           between Nabors Industries Ltd. and the directors and
                           executive officers identified in the schedule
                           thereto (incorporated by reference to Exhibit 10.28
                           to Nabors Industries Ltd.'s Form 10-K dated
                           December 31, 2002, File No. 000-49887, filed
                           March 31, 2003).

         10.21 (+)         Amended and Restated 1999 Stock Option Plan for
                           Non-Employee Directors (amended on May 2, 2003)
                           (incorporated by reference to Exhibit 10.29 to Nabors
                           Industries Ltd. 10-Q, File No. 000-49887, filed
                           May 12, 2003).

         10.22             2003 Employee Stock Option Plan (incorporated by
                           reference to Annex D of Nabors Notice of 2003 Annual
                           General Meeting of Shareholders and Proxy Statement,
                           File No. 000-49887, filed May 8, 2003).

         10.23             Purchase and Sale Agreement (Red River) by and among
                           El Paso Production Company and El Paso Production GOM
                           Inc., jointly and severally as Seller and Ramshorn
                           Investments, Inc., as Purchaser dated October 8,
                           2003.

         10.24             Purchase and Sale Agreement (USA) between El Paso
                           Production Oil & Gas USA, L.P., as Seller and
                           Ramshorn Investments, Inc., as Purchaser dated
                           October 8, 2003.

         10.25             Exploration Participation Agreement (South Texas) by
                           and between El Paso Production Oil & Gas Company and
                           El Paso Production Oil & Gas USA, L.P., jointly and
                           severally and Ramshorn Investments, Inc., dated
                           November 6, 2003.

         10.26             Exploration Participation Agreement (Catapult) by and
                           between El Paso Production Company, and Ramshorn
                           Investments, Inc., dated November 6, 2003.

         12                Computation of Ratios.

         13(1)             2003 Annual Report of Nabors Industries Ltd.

         14                Code of Ethics (Code of Business Conduct).

         21                Significant Subsidiaries of Nabors Industries Ltd.

         23                Consent of Independent Accountants.

         31.1              Rule 13a-14(a)/15d-14(a) Certification, executed by
                           Eugene M. Isenberg, Chairman and Chief Executive
                           Officer of Nabors Industries Ltd.
</Table>



<PAGE>


<Table>
<S>                        <C>
         31.2              Rule 13a-14(a)/15d-14(a) Certification, executed by
                           Bruce P. Koch, Vice President and Chief Financial
                           Officer of Nabors Industries Ltd.

         32.1              Certifications required by Rule 13a-14(b) or Rule
                           15d-14(b) and Section 1350 of Chapter 63 of Title 18
                           of the United States Code (18 U.S.C. 1350), executed
                           by Eugene M. Isenberg, Chairman and Chief Executive
                           Officer of Nabors Industries Ltd. and Bruce P. Koch,
                           Vice President and Chief Financial Officer of Nabors
                           Industries Ltd.
</Table>

----------

(1)      With the exception of the specific information expressly incorporated
         into Items 1, 2, 3, 5, 6, 7, 7A, 8 and 14 of this document, the 2003
         Annual Report is not deemed to be filed as part of this report.

(+)      Management contract or compensatory plan or arrangement


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.23
<SEQUENCE>3
<FILENAME>h13476exv10w23.txt
<DESCRIPTION>PURCHASE AND SALE AGREEMENT
<TEXT>
<PAGE>


                                                                   EXHIBIT 10.23


                           PURCHASE AND SALE AGREEMENT
                                   (RED RIVER)

         This Purchase and Sale Agreement (this "Agreement") is entered into
this 8th day of October, 2003, by and among EL PASO PRODUCTION COMPANY and EL
PASO PRODUCTION GOM INC., jointly and severally (collectively "El Paso") and
RAMSHORN INVESTMENTS, INC. ("Ramshorn").

         WHEREAS, Ramshorn desires to purchase an overriding royalty interest in
the Subject Leases INSOFAR and ONLY INSOFAR as the Subject Leases cover the
Subject Wells drilled and completed thereon and the Oil and Gas produced
therefrom, all as set forth herein; and

         WHEREAS, El Paso desires to drill and complete the Subject Wells;

         NOW THEREFORE, in consideration of the terms and provisions of this
Agreement, the adequacy of which is hereby acknowledged, El Paso and Ramshorn
agree as follows:

                                    ARTICLE I

                                   DEFINITIONS

         1.1 Capitalized Terms. As herein used the following words, terms or
phrases have the following meanings:

         "Act" is defined in Section 5.1.

         "AFE" means an authority for expenditure, which is a good faith
estimate prepared by El Paso of the costs of an operation, which may include a
ten percent (10%) contingency amount. An AFE to drill a new well has an
estimated cost to drill and plug and abandon a well if it is a dry hole and the
cost to complete the well.

         "Affiliate" means with respect to any Person ("first Person") any
Person (i) which controls either directly or indirectly such first Person, or
(ii) which is controlled directly or indirectly by such first Person, or (iii)
is directly or indirectly controlled by a Person which directly or indirectly
controls such first Person. "Control" in the case of a Person which is a
corporation means the right to exercise 50% or more of the voting rights in the
appointment of the board of directors, or other body performing similar
functions, of such Person.

         "After Payout Overriding Royalty Interest" is defined in Section
2.5(b).

         "Agents" is defined in Section 6.5.

         "Agreed Rate" means a rate equal to the rate of interest per annum
publicly announced from time to time by JPMorgan Chase Bank as its prime rate in
effect at its principal office in New York, New York on the first day of the
month in which a payment delinquency under Section 3.3 occurs, plus 1.00%.

         "Agreement" is defined in the preamble hereto.



<PAGE>


         "Alternate Well" is defined in Section 2.9.

         "Approved Independent Engineer" means Huddleston & Co. Inc. or another
independent petroleum engineer of recognized national standing selected by El
Paso and acceptable to Ramshorn, in its reasonable discretion.

         "Business Day" means any day of the year that is not a Saturday, Sunday
or other day in which commercial banks are authorized or required to remain
closed in Houston, Texas or New York, New York.

         "Cash Method of Accounting" means a method of accounting in which (i)
the Gross Proceeds for a month shall be the net amount recognized and recorded
during such month in El Paso's ledgers for sales of Oil and Gas produced from
the relevant wells and (ii) the Production Costs for a month shall be the net
amount paid or charged to the relevant wells by El Paso and recorded during such
month in El Paso's ledgers. Accordingly, by way of example only, sales of
January production of Oil and Gas will normally be used to determine Gross
Proceeds for the month of March.

         "Code" means the Internal Revenue Code of 1986, as amended.

         "Dry Well" means a Subject Well that has been drilled and then plugged
and abandoned as a dry hole.

         "El Paso" is defined in the preamble hereto.

         "Encumbrance" means any (i) mortgage, lien, security interest, pledge,
encumbrance or claim or (ii) royalty, overriding royalty, production payment,
net profits interest or like burden on, or prepaid or forward Sales Contract
covering, the Oil and Gas produced from any Subject Well.

         "Excess Production Costs" means, for any month, the amount of
Production Costs (plus any Excess Production Costs carried forward from a prior
month) in excess of Gross Proceeds for such month.

         "Gross Proceeds" means, for any month, the amount received on the Cash
Method of Accounting by El Paso, without duplication, from the Sale of Oil and
Gas produced from Subject Wells, subject to the following:

                  (a) If any gas is processed before the sale thereof, the
amount of the Gross Proceeds for such gas shall be the gross proceeds from the
sale of El Paso's proportionate share of the residue gas and liquid hydrocarbons
attributable to the processed gas as determined by the processing agreement, if
any, covering such gas or, if there is no gas processing agreement in place, the
amount of proceeds for such gas shall be the gross proceeds from the sale of El
Paso's proportionate share of the wellhead volume multiplied by the Btu content.

                  (b) There shall be excluded any amount for Oil and Gas
attributable to non-consent operations conducted with respect to any Subject
Well as to which El Paso shall be a non-consenting party and which is dedicated
to the recoupment or reimbursement of costs and



                                       2
<PAGE>


expenses of the consenting party or parties by the terms of the relevant
operating agreement, unit agreement, contract for development or other agreement
providing for such non-consent operations. Similar amounts received by El Paso
from non-consenting third parties shall be included in Gross Proceeds.

                  (c) If for any reason any purchaser or any other third party
withholds payment for any sales volume or El Paso's proportionate share thereof
of any Oil and Gas produced from a Subject Well, then amounts withheld by the
purchaser or any such third party shall not be considered to be received by El
Paso or part of the Gross Proceeds until actually collected by El Paso or El
Paso receives the production therefrom, but any interest, penalty or other
amount paid to El Paso in respect thereof shall be included in Gross Proceeds.

                  (d) Gross Proceeds shall not include the value of any Oil and
Gas unavoidably lost or used in operations on any Subject Well and plant
operations (including gas injection, compression, treating, transporting,
secondary recovery, pressure maintenance, repressuring, recycling operations,
plant fuel or shrinkage).

                  (e) There shall be excluded from Gross Proceeds any valid and
existing royalties, overriding royalties, production payments, and like burdens
on the Oil and Gas produced from the Subject Wells of record on or before
September 1, 2003; provided, however, if El Paso acquires an additional interest
in a Subject Lease after such date, then all royalties, production payments, and
like burdens on such interest existing at the date of acquisition shall also be
excluded from Gross Proceeds.

                  (f) Subject to (b) above, there shall be excluded from Gross
Proceeds any revenues received by El Paso that are attributable to the net
revenue interests of other working interest owners of the Oil and Gas produced
from any Subject Well.

                  (g) There shall be excluded from Gross Proceeds any amounts
received by El Paso from a purchaser of Oil and Gas as advance payments and
payments pursuant to take-or-pay and similar provisions of Sales Contracts until
such Oil and Gas is actually produced and delivered to such purchaser. When such
Oil and Gas is produced, then the market value of such Oil and Gas at the time
of such production shall be included in Gross Proceeds.

                  (h) During any month when El Paso is, for any Subject Well, an
Overproduced Party or an Underproduced Party under any gas balancing
arrangement, there shall be included in Gross Proceeds amounts received by El
Paso from a purchaser of Oil and Gas or an Overproduced Party as and when paid
to El Paso and when El Paso is required to make settlement in cash for any net
overproduction, such payment shall be deducted from the Gross Proceeds, if any.

                  (i) To the extent allocable to the Subject Wells, refunds of
revenues previously included as Gross Proceeds for such Subject Well required to
be made by El Paso (including any interest thereon or penalties) as a result of
the bankruptcy, insolvency or similar condition of a purchaser of production or
other party, an order of the Federal Energy Regulatory Commission, tax, or other
governmental unit or any other legal reason shall be deducted from Gross
Proceeds.



                                       3
<PAGE>


                  (j) To the extent allocable to a Subject Well, any amounts
paid in good faith by El Paso as a prudent owner or operator, whether as refund,
interest or penalty, to a purchaser because the amount initially received by El
Paso as the sales price attributable to Oil and Gas produced was more or
allegedly more than permitted by the terms of any applicable contract, statute,
regulation, order, decree or other obligation shall be deducted from Gross
Proceeds.

                  (k) Insurance proceeds received by El Paso relating to any
Subject Well shall be included in Gross Proceeds if such proceeds relate to
equipment or other property, the costs which were included in Investment Costs
or Production Costs.

                  (l) Proceeds of the sale of any equipment or other property
shall be included in Gross Proceeds if the original cost thereof was included as
an Investment Cost or a Production Cost.

                  (m) Net damages, after deducting court costs, expert fees,
attorney fees and other litigation costs, collected by El Paso and attributable
to a Subject Well in any litigation covering damage to reserves or reservoir
formations shall be included in Gross Proceeds.

                  (n) Proceeds of the sale of Permitted Third Party Net Profits
Interests shall not be included in Gross Proceeds.

         "Investment Costs" means the actual costs incurred on a Subject Well of
drilling, completing, equipping (including but not limited to flow lines, tanks,
and related equipment) to the point of product sales, and plugging and
abandoning (if a Subject Well was a dry hole) and the cost of recompleting to
another zone, deepening, side-tracking, or plugging and abandoning a well and
any other costs considered to be capital costs (and not expenses) under U.S.
generally accepted accounting principles, whether such costs were incurred
before or after the date of this Agreement.

         "Investment Invoice" is defined in Section 2.3.

         "Investment Percentage" is defined in Section 2.1.

         "Net Overriding Royalty Interest" is defined in Section 2.1.

         "Net Profits" means, for the Subject Wells for any month, the excess of
aggregate Gross Proceeds for such month over the sum of (i) aggregate Production
Costs for such month and (ii) aggregate Excess Production Costs as of the end of
the immediately preceding month, all on the Cash Method of Accounting.

         "Net Profits Account" is defined in Section 3.4.

         "Oil and Gas" means oil, gas, other liquid and gaseous hydrocarbons.

         "Overproduced Party" means a party to a gas balancing arrangement who,
as a result of producing, in addition to its own share of production, that
portion of another party's share of production which such other party is unable
or unwilling to market or otherwise to dispose of, is



                                       4
<PAGE>


in a position of net overproduction with respect to such other party or parties
to such gas balancing arrangement.

         "Payout Account" is defined in Section 2.4.

         "Payout Date" means the first day after the Project Completion Date on
which the balance in the Payout Account is equal to or less than zero.

         "Permitted Encumbrances" means any or all of the following:

                  (a) Encumbrances that arise under operating agreements to
secure payment of amounts not yet delinquent and are of a type and nature
customary in the oil and gas industry;

                  (b) Encumbrances that arise as a result of pooling and
unitization agreements, designations, declarations, orders or laws;

                  (c) Encumbrances securing payments to mechanics and
materialmen and Encumbrances securing payment of taxes or assessments that are,
in either case, not yet delinquent or, if delinquent, are being contested in
good faith in the normal course of business;

                  (d) consents to assignment by governmental authorities that
are customarily obtained after the consummation of transactions of the nature
contemplated by this Agreement;

                  (e) conventional rights of reassignment obligating El Paso to
reassign its interest in any portion of the Subject Leases to a third party in
the event El Paso intends to release or abandon such interest prior to the
expiration of the primary term or other termination of such interest;

                  (f) easements, rights-of-way, servitudes, permits, surface
leases, surface use restrictions and other surface uses and impediments on, over
or in respect of any of the Subject Leases that are not such as to interfere
materially with the operation, value or use of the Subject Leases, taken as a
whole;

                  (g) calls on or preferential rights to purchase production at
not less than market prices prevailing in the field, held by parties other than
El Paso or Affiliates of El Paso;

                  (h) such Encumbrances as Ramshorn has expressly waived in
writing;

                  (i) royalties, overriding royalties, production payments, and
like burdens on the Oil and Gas produced from any Subject Well existing of
record as of September 1, 2003;

                  (j) rights reserved to or vested in any municipality or
governmental, tribal, statutory or public authority to control or regulate any
of the Subject Leases in any manner, and all applicable laws, rules and orders
of any municipality or governmental or tribal, statutory or public authority;

                  (k) the terms and conditions of the Subject Leases;



                                       5
<PAGE>


                  (l) division orders and Sales Contracts terminable without
penalty upon no more than ninety (90) days' notice to the purchaser;

                  (m) preferential rights and required third party consents to
assignment and similar agreements with respect to which waivers or consents are
obtained from the appropriate parties, or the appropriate time period for
asserting any such right has expired without an exercise of the right;

                  (n) Permitted Third Party Net Profits Interests; and

                  (o) all other liens, charges, encumbrances, contracts,
agreements, instruments, obligations, defects and irregularities affecting the
Subject Leases that individually or in the aggregate are not such as to
materially interfere with the operation, value or use of any of the Subject
Wells and do not prevent Ramshorn from receiving its proportionate share of the
Net Profits before the Payout Date and after the Payout Date, the proceeds of
its After Payout Overriding Royalty Interest.

         "Permitted Third Party Net Profits Interests" means net profits
interests or net overriding royalty interests sold by El Paso to non-Affiliates
conveying an interest in Net Profits attributable to some or all of the Subject
Wells; provided, however, the total interest in Net Profits represented by all
Permitted Third Party Net Profits Interests and the Net Overriding Royalty
Interest shall not exceed seventy percent (70%); and provided further, however,
that the agreements, conveyances or other instruments creating, granting or
evidencing any such interests do not create or result in, or purport to create
or result in any priority over, or any rights whatsoever senior to, the rights
and interests of Ramshorn hereunder or under any conveyance or other instrument
executed by El Paso pursuant hereto.

         "Person" means any individual, corporation, partnership, trust, estate
or other entity or organization.

         "Present Value" means, for purposes of any purchase by El Paso from
Ramshorn pursuant to Section 5.3(a), the present value of the Net Overriding
Royalty Interest in the applicable Subject Well applying a ten percent (10%)
discount rate to the undiscounted future pre-tax net cash flows accruing to such
interest, minus all projected undiscounted future Investment Costs associated
therewith, as shown on the most current Reserve Report, from the effective date
of such purchase to the projected Payout Date and in the case of the After
Payout Overriding Royalty Interest into which such interest shall convert at the
Payout Date, the undiscounted future pre-tax net cash flows accruing to such
interest, as shown on the most current Reserve Report, from the projected Payout
Date to ultimate depletion of the Subject Well(s) burdened thereby.

         "Production Costs" for a month means, to the extent such costs are
allocable to El Paso's working interest in the Subject Wells and have been paid
by El Paso or charged by El Paso to such wells during such month under the Cash
Method of Accounting, without duplication:

                  (a) The sum of:



                                       6
<PAGE>


                  (i) costs of labor charged to the Subject Wells including
         salaries and wages, employee benefits, and miscellaneous employee costs
         provided for:

                           (1) field employees directly engaged in the operation
                  of any such well;

                           (2) first level supervisors engaged in the
                  supervision of the operation of any such well;

                           (3) technical employees employed on any such well if
                  such charges are not included in the per-well overhead rates
                  referred to below in subparagraph (iii) of this paragraph (a)
                  and not otherwise charged; and

                           (4) employees of shore bases or other facilities
                  serving any such well if such charges are not included in the
                  per-well overhead rates referred to below in subparagraph
                  (iii) of this paragraph (a) and not otherwise charged.

                  (ii) other direct costs allocated to the Subject Wells not
reimbursed by applicable insurance including:

                           (1) contract and professional services;

                           (2) materials, supplies, fuel, water, and treating
                  chemicals;

                           (3) salt water disposal;

                           (4) well and leasehold equipment repairs and
                  maintenance, including workovers;

                           (5) transportation including boats, aircraft, and
                  other vehicles;

                           (6) costs paid by El Paso, as the operator, for
                  dehydration, compression, separating, treating, storing,
                  gathering, and gas transportation of Oil and Gas to the point
                  of product sales;

                           (7) safety and environmental costs, including spill
                  cleanup, except for such costs attributable to El Paso's gross
                  negligence or willful misconduct;

                           (8) the costs of secondary recovery, pressure
                  maintenance, repressuring, recycling, and other operations
                  used to enhance production of Oil and Gas to the point of
                  product sales;

                           (9) to the extent directly allocable to a Subject
                  Well, (i) insurance including workman's compensation, general
                  liability, and (ii) the costs of certificates of
                  responsibility, performance bonds or letters of credit;



                                       7
<PAGE>


                           (10) other miscellaneous costs of operating,
                  producing, and maintaining a Subject Well for services or
                  supplies furnished by or on behalf of El Paso, as the
                  operator, which is of direct benefit to such well and incurred
                  in the necessary and proper conduct of operations thereon, and
                  which normally would be chargeable by an operator to the
                  "joint account" under a customary joint operating agreement
                  for similar wells; and

                           (11) costs incurred for claims, demands or litigation
                  relating to property damage, including environmental damages,
                  spills, clean-up and remediation, personal injury or death, or
                  claims, demands or litigation brought by third parties,
                  including governmental or regulatory authorities except for
                  such costs attributable to El Paso's gross negligence or
                  willful misconduct.

                  (iii) per well overhead in accordance with the provisions of
         the joint operating agreement accounting procedure covering a Subject
         Well or if none exists for a Subject Well, Section III of the
         accounting procedures attached hereto as Schedule I (Onshore) or
         Schedule II (Offshore), as applicable.

                  (iv) an amount equal to all general property (ad valorem),
         production, severance, sales, gathering, energy, BTU and similar state,
         federal, or other taxes (except income taxes) assessed or levied on or
         in connection with the Subject Wells, the Net Overriding Royalty
         Interest, or the production therefrom or equipment thereon or
         associated therewith, and which taxes (as adjusted or finally
         determined) are deducted or excluded from proceeds from the sale of Oil
         and Gas received by El Paso or paid by El Paso and attributable to both
         El Paso's and Ramshorn's share in the Oil and Gas; provided however,
         that if Ramshorn bears any such taxes individually, such taxes will not
         be considered to constitute Production Costs.

                  (b) Where production costs incurred for the benefit of a
Subject Well also benefit other wells or properties, El Paso will allocate
charges on an equitable and consistent basis.

                  (c) Production Costs for the Subject Wells shall not include:

                  (i) general and administrative costs that are not covered by
         the joint operating agreement accounting procedure covering a Subject
         Well or if none exists for a Subject Well, Section III of the
         accounting procedures attached hereto as Schedule I (Onshore) or
         Schedule II (Offshore), as applicable;

                  (ii) depreciation, depletion, or amortization; or

                  (iii) any payments to holders of Permitted Third Party Net
         Profits Interests.

                  (d) Any increased costs or liabilities that are borne by El
Paso as a result of its being a consenting party in non-consent operations on a
Subject Well shall be deemed to be allocable to or applicable to such Subject
Well.



                                       8
<PAGE>


                  (e) Production Costs shall include costs incurred after the
expiration of the Project Term with respect to operations on Subject Wells
notwithstanding that such costs may be properly characterized as capital costs
under U.S. generally accepted accounting principles.

         "Project Completion Date" is defined in Section 2.7.

         "Project Term" is defined in Section 8.2. Where the context requires,
references herein to the "Project Term" shall be deemed to be references to the
"Revised Project Term" as defined in Section 8.3.

         "Reserve Report" means any reserve report described in Section 6.6.

         "Sale" means and includes sales, assignments, transfers, exchanges and
other dispositions for value.

         "Sales Contract(s)" means all contracts and agreements for the offer or
sale of, or commitment to offer or sell, or right of first refusal to purchase,
Oil and Gas after production.

         "Subject Lease" or "Subject Leases" means the oil, gas and mineral
leases described in Exhibit "B" attached hereto as such Exhibit may be amended
from time to time as provided herein, including extensions and renewals of any
such lease obtained within six (6) months of the expiration thereof.

         "Subject Well" or "Subject Wells" means the oil and gas wells described
in Exhibit "A" attached hereto as such Exhibit may be amended from time to time
as provided herein.

         "Substitute Well" is defined in Section 2.8.

         "Underproduced Party" means a party to a gas balancing arrangement who,
as a result of its inability or unwillingness to market or otherwise dispose of
a portion of its share of production and another party's producing such share of
production, is in a position of net underproduction with respect to such other
party or parties to such gas balancing arrangement.

         "Well Cost Adjustment" means the difference, if any, between the
completed well cost as reflected in an AFE for a Subject Well and the actual
Investment Costs of such Subject Well (including costs which were not
contemplated in the AFE such as capital costs that are incurred after a well has
produced) as determined from time to time when the actual costs are determined;
provided, however, for purposes of determining any Well Cost Adjustment, no
Investment Cost incurred by El Paso after expiration of the Project Term will be
considered or included, and any such cost (regardless of its proper
characterization under U.S. generally accepted accounting principles) will be
considered and included as a Production Cost. The Well Cost Adjustment shall be
a positive number if the actual Investment Costs are higher than the AFE costs
and a negative number if the actual Investment Costs are lower than the AFE
costs.



                                       9
<PAGE>


                                   ARTICLE II
                                PURCHASE AND SALE

         2.1 Acquired Assets. Subject to the terms and conditions of this
Agreement, El Paso agrees to sell, convey and deliver to Ramshorn and Ramshorn
agrees to purchase and acquire from El Paso, subject to an after payout
conversion as provided for in Section 2.5(b), an overriding royalty interest in
the Subject Leases INSOFAR and ONLY INSOFAR as the Subject Leases cover the
Subject Wells and the Oil and Gas produced therefrom equal to the amount of the
Investment Percentage multiplied by the Net Profits from all the Subject Wells
(the "Net Overriding Royalty Interest"). The "Investment Percentage" shall be
twenty percent (20%), subject to adjustment as provided in Section 8.3.

         2.2 Purchase Price. The purchase price for the Net Overriding Royalty
Interest is the Investment Percentage of the amount of El Paso's proportionate
share (based upon El Paso's working interest in each Subject Well) of the total
Investment Costs of the Subject Wells commenced during the Project Term, and
which were incurred on or before the Project Completion Date.

         2.3 Payment of Purchase Price.

                  (a) By the last Business Day of each month, El Paso shall
invoice Ramshorn (an "Investment Invoice") for an amount equal to the Investment
Percentage of the sum of (i) the total of the estimated "Drill" costs as shown
in the AFE for each Subject Well commenced in the prior month multiplied by El
Paso's working interest in each such Subject Well, (ii) the total of the
estimated "Complete" and "Facilities" costs for each Subject Well on which El
Paso intends to commence completion operations in the following month or for
which completion operations have commenced plus (iii) any Investment Costs for
any operations on a Subject Well not contemplated in the AFE for drilling and
completing such Subject Well, but reasonably and directly related to, or
required in furtherance of, the specific drilling operation described in such
AFE, multiplied by El Paso's working interest in each such Subject Well, plus or
minus (iv) any Well Cost Adjustment on any Subject Well that had been determined
in the prior month multiplied by El Paso's working interest in such Subject
Well. The Investment Invoice shall not include any amount for the estimated
completed well costs as shown in the AFE for drilling and completing a Subject
Well commenced after the expiration of the Project Term or Investment Costs
incurred after the Project Completion Date.

                  (b) If an Investment Invoice is for a negative amount, then
the Payout Account shall be reduced by an amount equal to such amount multiplied
by one hundred seventeen and a half percent (117.5%) and El Paso shall pay to
Ramshorn the amount of such Investment Invoice with El Paso's next payment of
the Net Overriding Royalty Interest as provided in Section 3.2.

         2.4 Payout Account. The amount of all payments by Ramshorn for
Investment Invoices plus an additional 17.5% shall be credited to Ramshorn in an
account for all Subject Wells maintained by El Paso (the "Payout Account"),
which will be used to determine when all of the Net Overriding Royalty Interest
purchased by Ramshorn shall be suspended pursuant to Section 2.7 or converted
pursuant to Section 2.7(c). For example, if an AFE for drilling a


                                       10
<PAGE>


Subject Well is for $1,000,000 and El Paso's working interest is 100%, then El
Paso shall invoice Ramshorn for $200,000 and, upon payment of the invoice,
$235,000 shall be credited to the Payout Account. If an AFE for drilling a
Subject Well is for $1,000,000 and El Paso's working interest is 50%, then El
Paso shall invoice Ramshorn for $100,000 and, upon payment of the invoice,
$117,500 shall be credited to the Payout Account.

         2.5 Conveyance of Net Overriding Royalty Interest; Conversion.

                  (a) Within five (5) days after El Paso receives payment from
Ramshorn for an Investment Invoice, El Paso shall execute and deliver to
Ramshorn a recordable assignment substantially in the form attached hereto as
Exhibit "D-1" (for recordation in Texas) or "D-2" (for recordation in Louisiana)
of the Net Overriding Royalty Interest in the Subject Leases INSOFAR and ONLY
INSOFAR as the Subject Leases cover the Subject Wells whose drilling and
completion AFE was covered by such Investment Invoice and the Oil and Gas
produced therefrom. Each such assignment shall identify each Subject Well
covered thereby by name, location and API number.

                  (b) The Net Overriding Royalty Interest shall automatically
convert on the Payout Date into a perpetual overriding royalty interest in the
Subject Leases INSOFAR and ONLY INSOFAR as the Subject Leases cover the Subject
Wells that were covered by the Net Overriding Royalty Interest and the Oil and
Gas produced therefrom equal to the Investment Percentage (at the time of
conversion) times two percent (2%) of 8/8ths (the "After Payout Overriding
Royalty Interest"). The After Payout Overriding Royalty Interest shall be
proportionately reduced on a lease-by-lease basis, as follows:

                  (i) If El Paso owns less than the entire oil and gas leasehold
         estate created by any Subject Lease, the After Payout Overriding
         Royalty Interest shall be paid in the proportion which the fractional
         part of such leasehold estate owned by El Paso bears to the entire oil
         and gas leasehold estate created by such Subject Lease;

                  (ii) If any Subject Lease covers less than the entire oil and
         gas estate, the After Payout Overriding Royalty Interest shall be paid
         in the proportion which the fractional part of the oil and gas estate
         covered by the Subject Lease bears to the entire oil and gas estate;
         and

                  (iii) If any Subject Lease, or any part thereof, is pooled or
         unitized in a unit, the After Payout Overriding Royalty Interest shall
         be paid in the proportion that the acreage covered by the Subject Lease
         included in such unit bears to all the acreage included in such unit.

                  (c) After the Payout Date and within thirty (30) days from a
request by El Paso, Ramshorn shall execute and deliver to El Paso a Notice of
Conversion and Reconveyance of Overriding Royalty Interest in the form attached
hereto as Exhibit "E-1" (for recordation in Texas) and "E-2" (for recordation in
Louisiana) and return any data or materials acquired by Ramshorn pursuant to
this Agreement.

                  (d) If all of the Subject Wells are not commenced prior to the
end of the Project Term, El Paso shall continue to assign Ramshorn its Net
Overriding Royalty Interest in



                                       11
<PAGE>


each such Subject Well until the Payout Date. After the Payout Date, El Paso
shall not be obligated to assign Ramshorn any additional Net Overriding Royalty
Interests in Subject Leases or Subject Wells even as to Subject Wells commenced
prior to the Payout Date, but after the Project Term.

                  (e) If a Subject Well is plugged and abandoned, then at El
Paso's request Ramshorn shall execute and deliver to El Paso a Partial
Reconveyance and Termination of Overriding Royalty Interest in the form attached
hereto as Exhibit "F-1" (for recordation in Texas) or "F-2" (for recordation in
Louisiana) but limited to the Net Overriding Royalty Interest in such Subject
Well.

                  (f) Ramshorn shall not have the right or option to take in
kind any Oil or Gas attributable to the Net Overriding Royalty Interest or the
After Payout Overriding Royalty Interest.

         2.6 Memorandum of Purchase and Sale Agreement. El Paso shall
contemporaneously with the execution of this Agreement execute and file of
record, in each county in Texas wherein any lands covered by any Subject Lease
are located, a Memorandum of Purchase and Sale Agreement in the form attached
hereto as Exhibit "C." In lieu thereof, in each parish in Louisiana wherein any
lands covered by any Subject Lease are located, El Paso will file of record a
fully executed and properly witnessed original counterpart of a Declaration and
Agreement, in the form attached hereto as Exhibit "H.".

         2.7 Suspension of the Net Overriding Royalty Interest. Until the date
all of the Subject Wells commenced before the end of the Project Term have been
drilled, completed, and equipped or determined to be a Dry Well (the "Project
Completion Date"), Ramshorn's right to receive payment from the Net Overriding
Royalty Interest for all of the Subject Wells shall be suspended from time to
time whenever the amount in the Payout Account is equal to or less than zero.
Any Net Profits during such suspensions shall not be carried forward and El Paso
shall be entitled to keep such Net Profits. During such suspension of the Net
Overriding Royalty Interest, the Net Profits for the Subject Wells shall be
deemed to be zero. Such suspension(s) shall automatically cease when the amount
in the Payout Account is again greater than zero.

         2.8 Substitute Wells. In the event granite, salt, saltwater flow,
heaving shale or other conditions, including either the loss of the hole or
mechanical difficulties, are encountered in the drilling or completing of a
Subject Well drilled pursuant to the terms of this Agreement which would render
further operations impracticable in the opinion of El Paso, El Paso has the
right but not the obligation under this Agreement to commence the actual
drilling of a "Substitute Well", at a legal location to the same target
objective as the Subject Well after the plugging and abandoning of the Subject
Well during the period this Agreement is in place. Such Substitute Well shall
become a Subject Well and any reference to the Subject Wells shall include such
Substitute Well.

         2.9 Alternate Wells.

                  (a) If El Paso elects not to drill a Subject Well because (i)
of title, permitting, or logistical problems, or (ii) the results from drilling
prior wells or the acquisition, evaluation, of



                                       12
<PAGE>


additional geological, geophysical or other information eliminated such Subject
Well as a well El Paso desires to drill because such results were negative, then
El Paso may replace such Subject Well with an alternate well or wells
("Alternate Well(s)") described on Exhibit "A" attached hereto and made part
hereof. Such Alternate Well(s) shall become Subject Well(s) and any reference to
Subject Well(s) shall include such Alternate Well(s).

                  (b) In addition, if El Paso proposes to sell or otherwise
transfer a Subject Lease or Leases to a non-Affiliate in a bona fide, arm's
length transaction prior to the submission to Ramshorn of an Investment Invoice
related to the associated Subject Well(s) contemplated therefor, then El Paso
may replace such Subject Well with an Alternate Well. Such Alternate Well(s)
shall become Subject Well(s) and any reference to Subject Well(s) shall include
such Alternate Well(s).

                  (c) The Subject Wells and Alternate Wells are grouped in two
categories as shown on Exhibit "A." El Paso may replace Category 1 and 2 Subject
Wells with Category 1 Alternate Wells. El Paso may replace Category 2 Subject
Wells with Category 2 Alternate Wells. El Paso may replace Category 1 Subject
Wells with Category 2 Alternate Wells only with the consent of Ramshorn. El Paso
shall provide Ramshorn notice of any substitution pursuant to Section 2.7(a) in
the applicable Investment Invoice and notice of any substitution pursuant to
Section 2.7(b) not later than thirty (30) days prior to the proposed sale. Any
substitution of Alternate Well(s) for Subject Well(s) pursuant to Section 2.9(b)
shall be permitted only if the estimated ultimate reserves and total estimated
drilling and completion costs for the proposed Alternate Well(s) are
approximately equal to that of the Subject Well(s) for which El Paso has elected
to make a substitution under Section 2.9(b).

         2.10 Information About the Subject Wells. El Paso disclaims all
liability and responsibility for any representation, warranty (other than the
representations and warranties specifically set forth in this Agreement),
statements or communications (orally or in writing) to Ramshorn, including any
information contained in any opinion, information or advice that may have been
or in the future may be provided to Ramshorn by any employee, officer, director,
agent, consultant, engineer or engineering firm, trustee, representative,
partner, member, beneficiary, stockholder or contractor of El Paso wherever and
however made, including those made in any data room or internet site and any
supplements or amendments thereto or during any negotiations with respect to
this Agreement or any confidentiality agreement previously executed by El Paso
and Ramshorn with respect to the Subject Wells. EL PASO MAKES NO WARRANTY OR
REPRESENTATION, EXPRESS, STATUTORY OR IMPLIED, AS TO (i) THE ACCURACY,
COMPLETENESS OR MATERIALITY OF ANY DATA, INFORMATION OR RECORDS FURNISHED TO
RAMSHORN IN CONNECTION WITH THE SUBJECT WELLS, INCLUDING WITHOUT LIMITATION
SEISMIC DATA AND EL PASO'S INTERPRETATION AND OTHER ANALYSIS THEREOF; (ii) THE
PRESENCE, QUALITY AND QUANTITY OF HYDROCARBON RESERVES (IF ANY) ATTRIBUTABLE TO
THE SUBJECT WELLS; (iii) THE ABILITY OF THE SUBJECT WELLS TO PRODUCE
HYDROCARBONS, INCLUDING WITHOUT LIMITATION PRODUCTION RATES, DECLINE RATES AND
RECOMPLETION OPPORTUNITIES; (iv) ALLOWABLES OR OTHER REGULATORY MATTERS; (v) THE
PRESENT OR FUTURE VALUE OF THE ANTICIPATED INCOME, COSTS OR PROFITS, IF ANY, TO
BE DERIVED FROM THE SUBJECT WELLS; AND (vi) ANY PROJECTIONS. ANY DATA,



                                       13
<PAGE>


INFORMATION OR OTHER RECORDS FURNISHED BY EL PASO ARE PROVIDED TO RAMSHORN AS A
CONVENIENCE AND RAMSHORN'S RELIANCE ON OR USE OF THE SAME IS AT RAMSHORN'S SOLE
RISK.

         2.11 Independent Investigation. Ramshorn has made its own independent
investigation, analysis and evaluation of the transactions contemplated by this
Agreement (including Ramshorn's own estimate and appraisal of the extent and
value of the Oil and Gas reserves attributable to the Subject Wells and the
costs to explore for and develop the reserves if found). Prior to execution of
this Agreement, Ramshorn has had access to all information necessary to perform
its investigation and not relied on any representations by El Paso (other than
the representations specifically set forth in this Agreement). El Paso has
provided Ramshorn and its experts the opportunity to review El Paso's data on
the Subject Wells and Ramshorn has reviewed such data that it deems necessary.
Ramshorn understands and acknowledges that El Paso is not guaranteeing the
actual costs of vendors supplying services to the Subject Wells.

         2.12 Waiver of Deceptive Trade Practices Acts. RAMSHORN WAIVES ITS
RIGHTS UNDER THE DECEPTIVE TRADE PRACTICES ACT SECTION 17.41 et seq., TEXAS
BUSINESS & COMMERCE CODE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS, AND UNDER
SIMILAR STATUTES ADOPTED IN OTHER STATES, TO THE EXTENT THEY HAVE APPLICABILITY
TO THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. AFTER CONSULTATION WITH AN
ATTORNEY OF ITS SELECTION, RAMSHORN CONSENTS TO THIS WAIVER.

         2.13 Net Revenue Interest. El Paso represents and warrants that its
average aggregate ratio of net revenue interest to working interest for the
Subject Wells is not less than seventy percent (70%). Upon conversion of the Net
Overriding Royalty Interest as provided in Section 2.5(b), Ramshorn waives all
remedies for any breach of the foregoing representation.

         2.14 Encumbrances. El Paso represents and warrants that at the time any
Investment Invoice is submitted to Ramshorn for payment, and at the time the
related Assignment of Overriding Royalty Interest is filed of record in the
appropriate jurisdiction, the Subject Leases to which such invoice relates (to
the extent such leases contribute acreage for the Subject Well(s) to be drilled
thereon) shall be free and clear of any Encumbrances except Permitted
Encumbrances.

         2.15 Additional El Paso Representations and Warranties. El Paso hereby
represents and warrants to Ramshorn that:

                  (a) Each of El Paso Production and El Paso GOM is a
corporation duly incorporated, validly existing and in good standing under the
laws of its jurisdiction or incorporation, duly qualified and in good standing
as a foreign corporation in Texas and Louisiana and has all corporate power and
all material governmental licenses, authorizations, permits, consents and
approvals required to carry on its business as now conducted.

                  (b) The execution, delivery and performance by each of El Paso
Production and El Paso GOM of this Agreement and the performance by each of El
Paso Production and El



                                       14
<PAGE>


Paso GOM of its obligations hereunder are within its corporate powers and have
been duly authorized by all necessary corporate action on the part of each of El
Paso Production and El Paso GOM. This Agreement constitutes a valid and binding
agreement of each of El Paso Production and El Paso GOM enforceable in
accordance with its terms, except as (i) the enforceability hereby may be
limited by bankruptcy, insolvency, moratorium or similar laws affecting the
enforcement of creditors' rights generally and (ii) the availability of
equitable remedies may be limited by equitable principles of general
applicability.

                  (c) The execution, delivery and performance by El Paso of
their obligations hereunder do not and will not (i) contravene or conflict with
the certificate of incorporation or bylaws of either of El Paso Production or El
Paso GOM, (ii) contravene or conflict with or constitute or default (without
regard to any requirement of notice or the lapse of time or both) any provision
of any law, regulation, judgment, injunction, order or decree binding upon or
applicable to either of El Paso Production or El Paso GOM, or any indenture,
mortgage, lien, lease, agreement or instrument to which either of El Paso
Production or El Paso GOM is a party or by which either of them or any of their
respective assets or properties is bound.

         2.16 Ramshorn Representations and Warranties. Ramshorn hereby
represents and warrants to El Paso that:

                  (a) Ramshorn is a corporation duly incorporated, validly
existing and in good standing under the laws of its jurisdiction of
incorporation, and has all corporate power and all material governmental
licenses, authorizations, permits, consents and approvals required to carry on
its business as now conducted.

                  (b) The execution, delivery and performance by Ramshorn of
this Agreement and the performance by Ramshorn of its obligations hereunder are
within its corporate powers and have been duly authorized by all necessary
corporate action on the part of Ramshorn. This Agreement constitutes a valid and
binding agreement of Ramshorn enforceable in accordance with its terms, except
as (i) the enforceability hereby may be limited by bankruptcy, insolvency,
moratorium or similar laws affecting the enforcement of creditors' rights
generally and (ii) the availability of equitable remedies may be limited by
equitable principles of general applicability.

                  (c) The execution, delivery and performance by Ramshorn of its
obligations hereunder do not and will not (i) contravene or conflict with the
certificate of incorporation or bylaws of Ramshorn, (ii) contravene or conflict
with or constitute or default (without regard to any requirement of notice or
the lapse of time or both) any provision of any law, regulation, judgment,
injunction, order or decree binding upon or applicable to Ramshorn, or any
indenture, mortgage, lien, lease, agreement or instrument to which Ramshorn is a
party or by which it or any of its assets or properties is bound.

                                   ARTICLE III
                                    PAYMENTS

         3.1 Payments by Ramshorn. Ramshorn shall pay each Investment Invoice by
wire transfer to El Paso's account on or before fifth (5th) Business Day of the
month following the month in which Ramshorn receives such Investment Invoice.



                                       15
<PAGE>


         3.2 Payments by El Paso.

                  (a) The Net Overriding Royalty Interest for the Subject Wells
shall be calculated collectively using the Cash Method of Accounting. For each
month, the Net Overriding Royalty Interest for the Subject Wells shall be paid
to Ramshorn on the seventh (7th) Business Day of the month following such month.
For example, the Net Overriding Royalty Interest for the month of January (which
normally includes revenues for the sale of Oil and Gas produced in November)
will be paid on or before the seventh (7th) Business Day of February. Each such
payment made shall reduce the Payout Account balance pro tanto.

                  (b) The After Payout Overriding Royalty Interest shall be
calculated in the same manner and paid at the same time that El Paso pays the
lessors under the Subject Leases.

                  (c) Pending payment over of the Net Profits accruing to the
Net Overriding Royalty Interest and, if applicable, the proceeds accruing to the
After Payout Overriding Royalty Interest, the same shall be held by El Paso for
the benefit of Ramshorn.

         3.3 Interest on Past Due Payments. Any undisputed amount not paid by El
Paso or Ramshorn when due shall bear, and the owing party will pay, interest at
the Agreed Rate or the maximum contract rate permitted by the applicable usury
laws in the state in which the Subject Wells are located, whichever is less,
plus attorney's fees, court costs, and other costs in connection with the
collection of unpaid amounts.

         3.4 Net Profits Account.

                  (a) A single account (the "Net Profits Account") shall be
maintained by El Paso for the Subject Wells. The Net Profits Account shall be
credited with the aggregate Gross Proceeds received by El Paso, and shall be
charged with the aggregate Production Costs (or as the case may be, Excess
Production Costs) with respect to the Subject Wells, in each case using the Cash
Method of Accounting.

                  (b) On or before the date of payment as set forth in Section
3.2 hereof, El Paso shall furnish to Ramshorn a detailed statement clearly
reflecting the credits and debits to on a per well basis, and the balance of,
the Net Profits Account and the Payout Account as of the close of business on
the last Business Day of the preceding calendar month. Any Excess Production
Costs reflected by any such statement shall be carried forward to the next and
succeeding month or months until the Excess Production Costs shall have been
liquidated. In the event that Net Profits exist in the Net Profits Account at
the end of any month, payment to Ramshorn of the amount of Net Profits pursuant
to Section 3.2 shall be accomplished by wire transfer to Ramshorn's account,
pursuant to instructions given by Ramshorn to El Paso. Following any such
payment, the balances of the Net Profits Account and the Payout Account shall be
reduced by the amount of such payment.

                                   ARTICLE IV
                             POOLING AND UNITIZATION

         4.1 Pooling. Prior to the Payout Date, El Paso shall have the right and
power to pool and unitize any of the Subject Leases and to alter, change or
amend or terminate any pooling or



                                       16
<PAGE>


unitization agreements heretofore or hereafter entered into, as to all or any
part of the land covered hereby, and as to Oil, Gas or both, upon such terms and
provisions as El Paso shall, in conformance with prudent industry practices and
the relevant Subject Leases, determine. If and whenever through the exercise of
such right and power, or pursuant to any law now in effect or hereafter enacted
or any rule, regulation or order of any governmental body or official, any of
the Subject Leases are pooled or unitized in any manner, the Net Overriding
Royalty Interest insofar as it affects such Subject Leases shall also be pooled
and unitized and in any such event such Net Overriding Royalty Interest in such
Subject Leases shall apply to and affect only the production from the relevant
Subject Well (and not any other wells within such unit except as set forth in
Section 4.2) which accrues to such Subject Leases under and by virtue of the
pooling and unitization. In such event, Ramshorn's Investment Percentage shall
not change; however, Ramshorn's Net Profits from the Subject Wells may increase
or decrease due to an increase or decrease in El Paso's net revenue interest in
the unitized Subject Well.

         4.2 Adjustment to Net Overriding Royalty Interest. If such pooling or
unitization occurs before the Payout Date and after El Paso had invoiced
Ramshorn for the pooled or unitized Subject Well, then any amounts paid or
received by El Paso for a capital cost adjustment as a result of such pooling or
unitization shall be included as an increase or decrease, respectively, in the
Investment Costs of such well and reflected in a Well Cost Adjustment. If there
are other wells in such pooled acreage or unit in which El Paso acquires an
interest as the result of such pooling or unitization and such capital cost
adjustment, then El Paso shall assign a Net Overriding Royalty Interest in such
wells to Ramshorn. Ramshorn shall not have any interest in any subsequent well
drilled in such pooled acreage or unit unless such well is a Subject Well.

                                    ARTICLE V
                                   ASSIGNMENTS

         5.1 Restriction on Ramshorn's Assignment. The sale of the Net
Overriding Royalty Interest has not been registered under the Securities Act of
1933, as amended (the "Act") and the Net Overriding Royalty Interest may not be
sold or transferred in the absence of an effective registration statement under
the Act or the availability of an exemption from registration thereunder,
including the exemption for any transfers to "qualified institutional buyers" as
defined in and in accordance with Rule 144A as promulgated under the Act.
Ramshorn may transfer or assign any portion of its rights and obligations
hereunder, the Net Overriding Royalty Interest and/or the After Payout
Overriding Royalty Interest to any Affiliate of Ramshorn. Prior to the
expiration of the Project Term, Ramshorn may transfer or assign any portion of
its rights and obligations hereunder and the Net Overriding Royalty Interest to
any such "qualified institutional buyer"; provided, however, such assignment or
transfer must be approved by El Paso, which approval shall not unreasonably be
withheld. After the expiration of the Project Term, Ramshorn may transfer any of
the Net Overriding Royalty Interest or the After Payout Overriding Royalty
Interest and its rights hereunder without restriction, subject to compliance
with any applicable securities laws or regulations; provided, however, if the
Net Overriding Royalty Interest or the After Payout Overriding Royalty Interest
is divided among and owned by four (4) or more co-owners, El Paso, at its
discretion, may require such co-owners to appoint Ramshorn as agent, with full
authority to enter into and execute division orders or other agreements for
disposition of the co-owners' respective shares of Oil and Gas produced from the



                                       17
<PAGE>


Subject Wells, and to receive payment of the proceeds from the sale thereof; and
provided further, however, in the case of assignments or transfers after the
expiration of the Project Term but before the Payout Date, each assignee or
transferee must acknowledge in writing that it and the Net Overriding Royalty
Interest are subject to this Agreement.

         5.2 Assignments by El Paso. If El Paso assigns its interest in a
Subject Well before the Payout Date, then it shall notify the assignee of the
existence of this Agreement and secure a written acknowledgement that the
Subject Well being assigned is specifically subject to the rights of Ramshorn as
set forth herein. El Paso will then provide Ramshorn with a copy thereof.

         5.3 Purchase by El Paso.

                  (a) If El Paso intends to sell its entire interest in a
Subject Well for cash to a non-Affiliate in a bona fide, arm's-length
transaction prior to the date at which the cumulative amount of proceeds paid or
payable by the buyer(s) for all Subject Well(s) theretofore sold or proposed to
be sold equals or exceeds $10,000,000, then El Paso shall have the option to
purchase Ramshorn's Net Overriding Royalty Interest and After Payout Overriding
Royalty Interest in the affected Subject Well by paying to Ramshorn an amount in
cash equal to the Present Value of its Net Overriding Royalty Interest and After
Payout Overriding Royalty Interest.

                  (b) If El Paso intends to sell its entire interest in a
Subject Well in a transaction described in Section 5.3(a) after the date
referred to therein, then El Paso shall have the option to purchase Ramshorn's
Net Overriding Royalty Interest and After Payout Overriding Royalty Interest in
the affected Subject Well by paying Ramshorn an amount in cash equal to (i) the
Investment Percentage multiplied by (ii) the net sale proceeds attributable to
such well.

                  (c) Upon payment by El Paso to Ramshorn of the applicable
purchase price as specified in Section 5.3(a) or (b), Ramshorn shall execute and
deliver to El Paso a Partial Reconveyance and Termination of Overriding Royalty
Interest covering such interest substantially in the form attached hereto as
Exhibit "F-1" (for recordation in Texas) or "F-2" (for recordation in
Louisiana). The amount of such payment shall be deducted from the Payout
Account. If a Subject Well(s) is to be sold in a transaction that includes other
El Paso properties, the portion of the proceeds allocable to the Subject Well(s)
shall be determined by reference to the buyer's purchase price allocation, made
in good faith, or if no such allocation exists, the allocation shall be
determined by El Paso in the exercise of its good faith judgment. At least ten
(10) Business Days prior to the consummation of any transaction covered by this
Section 5.3, El Paso will provide Ramshorn with a written notice thereof and
detail with respect to the purchase price allocation (if applicable) sufficient,
in Ramshorn's judgment, to enable it to address the reasonableness of the
allocation. If Ramshorn disputes the allocation and the parties cannot resolve
the matter themselves, the dispute will be referred to Netherland, Sewell &
Associates, Inc. for determination of an allocation for purposes of this Section
5.3, whose decision will be final.

                  (d) El Paso's purchase option provided for in this Section 5.3
shall terminate at the Payout Date.



                                       18
<PAGE>


                                   ARTICLE VI
                               RECORDS AND REPORTS

         6.1 Books and Records. El Paso shall at all times maintain true and
correct books and records sufficient to determine the amounts payable to
Ramshorn hereunder, including, but not limited to, a Net Profits Account to
which Gross Proceeds, Production Costs and Excess Production Costs are credited
and charged, and a Payout Account.

         6.2 Audits. Ramshorn, upon notice in writing to El Paso, shall have the
right to audit El Paso's accounts and records relating to the Net Profits
Accounts, Payout Account and After Payout Overriding Royalty Interest for any
calendar year within the twenty-four (24) month period following the end of such
calendar year; provided, however, the making of an audit shall not extend the
time for the taking of written exception to and the adjustments of accounts as
provided for in Section 6.4 of this Agreement. El Paso shall bear no portion of
Ramshorn's audit cost incurred under this Section 6.2 unless agreed to by El
Paso. The audits shall not be conducted more than once each year without prior
approval of El Paso. Unless prohibited under confidentiality agreements, El
Paso, upon written request, shall furnish Ramshorn with any and all accounting
information pertaining to the Subject Wells in El Paso's possession. Ramshorn
shall reimburse El Paso, at its option, for all reasonable costs incurred to
furnish such information.

         6.3 Statement and Reports. Until the Payout Date, on or before the date
of payment as specified in Section 3.2 hereof, El Paso shall deliver to Ramshorn
a statement showing the computation of Net Profits attributable to the
immediately preceding month and the computation of Net Profits paid to Ramshorn
from the date hereof until the end of such month. Such report shall be in form
satisfactory to Ramshorn, and shall include, among other things reasonably
requested by Ramshorn, historical and forecast production volumes for the
Subject Wells, summary reports of drilling and completion activities on drilling
or completed Subject Wells during such month, anticipated spud dates for other
Subject Wells as at the end of such month and such other information as Ramshorn
may reasonably require. After the Payout Date, El Paso shall deliver to
Ramshorn, with each cash payment of After Payout Overriding Royalty Interest
proceeds, a statement in such detail as is required by applicable laws or
regulations governing payments of oil and gas royalties, and with such
additional detail as Ramshorn may reasonably specify reflecting the computation
of such payment. Upon Ramshorn's request, El Paso will provide Ramshorn with
copies of any drilling or division order title opinions obtained by El Paso
covering any Subject Wells and reasonable access to El Paso's land files related
to such wells.

         6.4 Ramshorn's Exceptions to Statements. If Ramshorn takes exception to
any item or items included in the monthly statements rendered by El Paso to the
computations of the pricing or volumes of any Oil and Gas and such exception is
made within two (2) years after such monthly payment date, Ramshorn shall notify
El Paso in writing, setting forth in such notice the specific charges complained
of and to which exception is taken or the specific credits which should have
been made and allowed; and with respect to such complaints and exceptions as are
justified, adjustment shall be made. Any exception not made within such two (2)
year period shall be deemed waived and not subject to further audit.



                                       19
<PAGE>


         6.5 Geological Data. Prior to the Payout Date, El Paso shall, subject
to their reasonable availability and the limitations of confidentiality
undertakings with co-owners or other third parties, at Ramshorn's cost and
expense furnish Ramshorn and its duly authorized agents and representatives,
including its advisers and consultants (herein collectively referred to as its
"Agents"), copies of all electric and other logs of the Subject Wells. Prior to
the Payout Date, Ramshorn and its Agents shall also have access to all records
regarding all cores, cuttings, and other geological, well and production data
secured from operations on the Subject Wells. Ramshorn shall not have access to
any seismic data in El Paso's possession. After the Payout Date, Ramshorn and
its representatives shall have access to all records regarding production data,
future capital investment plans, marketing arrangements, processing arrangements
and any other data necessary, as determined by Ramshorn in its reasonable
discretion, to evaluate Ramshorn's After Payout Overriding Royalty Interest. All
information furnished to Ramshorn pursuant to this Section 6.5 is confidential
and for the sole benefit of Ramshorn and shall not be shown or disclosed by
Ramshorn to any Person except as provided in the Confidentiality Agreement dated
April 23, 2003, by and between El Paso and Ramshorn Brothers, Inc.

         6.6 Reserve Reports. El Paso will furnish or cause to be furnished the
following reserve reports:

                  (a) Promptly after December 31 of each calendar year
(commencing with the calendar year 2003), and in any event not later than March
31 of the next succeeding calendar year, a reserve report covering the Subject
Wells in the form prepared by the Approved Independent Engineer for El Paso for
its oil and gas properties, as of December 31 of such calendar year;

                  (b) Promptly after March 31, June 30 and September 30 of each
calendar year (commencing with the calendar year 2004), and in any event not
later than May 15, August 15 and November 15, respectively, of such calendar
year, a reserve report covering the Subject Wells in the form prepared by El
Paso as of the end of such calendar quarter and, in the case of such reports
prepared after January 1, 2004, updating the current Reserve Report prepared by
the Approved Independent Engineer; and

                  (c) Each such report shall conform to the standards prescribed
by Rule 4-10 of Regulation S-X promulgated by the Securities and Exchange
Commission under the Act for financial accounting and reserve reporting purposes
applicable to registrants employing the full cost method of accounting.

         6.7 Reconciliation Report. At March 31, 2004, and if requested by
Ramshorn at September 30, 2004 and March 31, 2005, El Paso shall deliver to
Ramshorn a report reconciling on a per well basis all amounts reflected in
Investment Invoices submitted to Ramshorn prior to the date of such report (or
if applicable, since the date of the most recent such report) to actual
Investment Costs for each Subject Well covered by any such invoice. At
Ramshorn's request, the parties shall meet to review the report(s) and if the
applicable reconciliation reveals that estimated costs reflected in the
Investment Invoices covered by such reconciliation routinely and, in the
reasonable judgment of Ramshorn, materially exceeded the actual costs (it being
understood that the inclusion of a 10% contingency amount shall not be
considered for this purpose), the parties will negotiate in good faith with a
view toward adjusting El Paso's



                                       20
<PAGE>


invoicing practices. If the parties are unable to reach agreement, Ramshorn may
require that future Investment Invoices be submitted based upon the last
estimated costs of the drilling and completion of the Subject Wells furnished by
El Paso to Ramshorn prior to the execution of this Agreement.

                                   ARTICLE VII
                           OPERATION OF SUBJECT LEASES

         7.1 Prudent Operator Standard.

                  (a) El Paso will conduct and carry on or cause to be conducted
and carried on the exploration, development, maintenance and operation of the
Subject Wells with reasonable and prudent business judgment and in accordance
with sound oil and gas field practices. Without limitation of the foregoing,
prior to commencement of drilling operations on any Subject Well, El Paso will
obtain a drilling title opinion or, in the case of a drillsite which is held by
production, conduct such other title review and related due diligence as would
be consistent with sound oil and gas field practices for the location and nature
of such drillsite and related Subject Well.

                  (b) Nothing contained in this Agreement shall be deemed to
prevent or restrict El Paso from electing to participate or not to participate
in any operation which is to be conducted under the terms of any operating
agreement, unit operating agreement, contract for development or similar
instrument affecting or pertaining to the Subject Wells (or any operation
conduced on a Subject Well) or if El Paso elects not to participate (which
election shall be made without taking into consideration the Net Overriding
Royalty Interest) allowing consenting parties to conduct non-consent operations
thereon.

                  (c) Nothing contained in this Agreement shall be deemed to
prevent or restrict El Paso from drilling or participating in the drilling of
other oil and gas wells (which are not Subject Wells) on the Subject Leases and,
except as provided in Section 4.2, Ramshorn shall have no interest in such other
wells drilled on the Subject Leases or production therefrom.

                  (d) Any conveyance, assignment, or Encumbrance made by El Paso
or Ramshorn on the Subject Wells or Subject Leases insofar as the Subject Leases
cover the Subject Wells shall be made expressly subject to this Agreement and
Ramshorn's Net Overriding Royalty Interest or, if applicable, After Payout
Overriding Royalty Interest, and any Encumbrance made by El Paso (other than a
Permitted Third Party Net Profits Interest) or Ramshorn shall be made expressly
subordinate to the rights of the other party. Except for such expressly
subordinated conveyances, assignments and Encumbrances, and except for Permitted
Encumbrances, (i) prior to the recordation of an assignment to Ramshorn of the
Net Overriding Royalty Interest therein, El Paso at its own expense will keep
and maintain the Subject Wells and the Subject Leases insofar as the Subject
Leases cover and contribute to the Subject Wells free and clear of all
Encumbrances, except Permitted Encumbrances, arising by, through or under El
Paso or any Affiliate and (ii) after such recordation, El Paso at its own
expense will keep and maintain Ramshorn's Net Overriding Royalty Interest or, if
applicable, After Payout Overriding Royalty Interest free and clear of all
Encumbrances, except Permitted Encumbrances, arising by, through or under El
Paso or any Affiliate; provided, however, only for purposes of El Paso's



                                       21
<PAGE>


special warranty of title set forth in this sentence, Permitted Third Party Net
Profits Interests shall not be considered Permitted Encumbrances. Should an
adverse claim be made against, or a cloud develop upon the title to any part of
Ramshorn's Net Overriding Royalty Interest other than such as may arise by,
through or under El Paso or Ramshorn or a Permitted Encumbrance, unless
otherwise agreed by Ramshorn, El Paso will take all commercially reasonable
actions to defend such claim or to remove such cloud, the expenses of which
defense or removal shall be Production Costs hereunder.

                  (e) Oil and Gas from the Subject Wells shall be sold for
market value.

         7.2 Abandonment of Properties. Nothing herein contained shall obligate
El Paso to drill or complete any Subject Well, to continue to operate any
Subject Well, or to operate or maintain in force or attempt to maintain in force
any of the Subject Leases when, in El Paso's reasonable opinion, such well or
Subject Lease is not economical.

         7.3 Affiliated Transactions. El Paso may agree, contract or arrange
with itself or any of its Affiliates for the performance of services or the sale
or lease of equipment, and supplies used in connection with the Subject Leases,
and the payment of compensation therefor, as if such parties were independent
contractors; provided, however, that the terms of such agreement, contract or
arrangement are embodied in a written document setting forth the specific
arrangements; and provided further, however, that the compensation for such
services or sale or lease shall be (i) comparable to and competitive with that
of unrelated third parties rendering comparable services or selling or leasing
equipment or supplies in the same geographical area and (ii) paid only for
services, equipment or supplies reasonably necessary for the prudent operation
of, and actually furnished with respect to, such Subject Leases.

         7.4 Delay Rentals, Minimum Royalties, and Shut-in Gas Payments. El Paso
shall use its reasonable commercial efforts to pay or cause to be paid in a
proper and timely manner any delay rentals, minimum royalties, and shut-in gas
payments, if any, which may be necessary to maintain in force and effect the
Subject Leases, except any portion thereof which El Paso has determined to
abandon pursuant hereto. Notwithstanding anything to the contrary herein, El
Paso shall not be liable to Ramshorn for any failure to pay or the incorrect
payment of any delay rentals, minimum royalty, shut-in gas payments, or any
other contractual obligation, unless such failure shall be attributable to the
gross negligence or willful misconduct of El Paso.

         7.5 Accounting. El Paso shall account for revenues and costs associated
with the Subject Wells consistent with its normal business practices for other
wells in the region of the Subject Wells unless this Agreement requires a
different accounting.

                                  ARTICLE VIII
                              TERM AND TERMINATION

         8.1 Term. This Agreement shall terminate ninety (90) days after the
Payout Date; provided, however, any obligation to pay money under this Agreement
accruing to the Net Overriding Royalty Interest or After Payout Overriding
Royalty Interest or to convey or re-convey any interest in a Subject Lease or
Subject Well shall not terminate.



                                       22
<PAGE>


         8.2 Project Term. The "Project Term" shall refer to the period ending
on June 30, 2005.

         8.3 Early Termination of Project Term. Either party may notify the
other party in writing and terminate the Project Term effective thirty (30) days
after such notice is received by the other party. The shortened Project Term is
referred to hereinafter as the "Revised Project Term". This Agreement shall
continue to cover all Subject Wells that had been commenced prior to the
expiration of the Revised Project Term. In the event Ramshorn requests the early
termination of the Project Term, any Subject Wells that had not yet been
commenced on or before the expiration of the Revised Project Term shall be
automatically deleted from Exhibit "A" to this Agreement and shall no longer be
considered "Subject Wells." In the event El Paso requests the early termination
of the Project Term or if all of the Subject Wells have not been commenced by
the end of the original Project Term, then, in such event (i) Ramshorn shall,
until the Payout Date, receive its Net Overriding Royalty Interest in all of the
Subject Wells regardless of when such wells are commenced, even if following the
end of the Revised Project Term or original Project Term, as applicable, (ii)
the Investment Percentage shall be adjusted effective as of the first day of
each calendar quarter to be equal to the total purchase price paid by Ramshorn
under Section 2.2 divided by total Investment Costs of the Subject Wells which
are commenced prior to the Payout Date, and (iii) Ramshorn shall not be required
to pay any amounts under Section 2.2 or otherwise related to the Subject Wells
commenced after the end of the Revised Project Term or original Project Term, as
applicable. Whenever the Investment Percentage is adjusted, El Paso and Ramshorn
shall execute an Amendment to Assignment of Overriding Royalty Interest
substantially in the form attached hereto as Exhibit "G-1" (for recordation in
Texas) and "G-2" (for recordation in Louisiana).

         8.4 Deemed Early Termination by Ramshorn. In the event of any unexcused
failure, inability or refusal by Ramshorn to pay any undisputed portion of an
Investment Invoice within fifty-nine (59) days from the due date of such
invoice, then Ramshorn shall be deemed to have elected to terminate the Project
Term effective as of the first day of the month immediately preceding the month
in which such invoice was due; provided, however, if such payment default occurs
with respect to an Investment Invoice rendered at a time when any prior payment
default remains uncured, the period within which such default may be cured with
respect to such invoice shall be twenty-nine (29) days, in lieu of the
fifty-nine (59)-day period otherwise provided for above.

                                   ARTICLE IX
                                  MISCELLANEOUS

         9.1 Further Assurances. Should any additional instruments of assignment
and conveyance be required to describe more specifically any interests subject
hereto, El Paso and Ramshorn agree to execute and deliver the same. Also, if any
other or additional instruments are required in connection with the transfer of
any State or Federal lease interests in order to comply with applicable laws or
regulations, El Paso and Ramshorn will execute and deliver the same. Without
limitation of the foregoing, where Exhibit "A" indicates that a Subject Well is
a "drill to earn" prospect or proposed to be located on lands covered by leases
not yet assigned, or words to similar effect, promptly upon assignment to El
Paso of the affected leasehold interest(s), El Paso will prepare and the parties
will execute an amendment to the Memorandum of Purchase and



                                       23
<PAGE>


Sale Agreement, or Declaration and Agreement, as appropriate, to be filed in the
appropriate county or parish; provided, however, such amendments need be filed
no more often than once a month (but in any event, as to any particular Subject
Lease assigned to or acquired by El Paso after the date hereof, prior to the
submission to Ramshorn of an Investment Invoice related to the Subject Well
proposed to be drilled thereon); and provided further, however, if El Paso is
not entitled to receive an assignment until completion of a Subject Well because
such well is drilled under a farmout or similar "drill to earn" agreement, the
parenthetical in the foregoing proviso shall not be applicable.

         9.2 Notices. Except as otherwise expressly provided in this Agreement,
all notices, demands, requests or other communications required or permitted to
be given pursuant to this Agreement shall be in writing and may be given either
(i) in person, (ii) by United States mail, certified or registered, return
receipt requested, postage prepaid, (iii) by nationally recognized overnight
courier or (iv) by prepaid telegram, telex, cable, telecopy or similar means
(with signed confirming copy to follow by mail), as follows:


                  IF TO EL PASO:

                  Nine Greenway Plaza
                  Houston, Texas  77046
                  Attention:  J. T. Elzner
                  Telephone:  832.676.7817
                  Fax:  832.676.1353

                  IF TO RAMSHORN:

                  Ramshorn Investments, Inc.
                  515 W. Greens Road, Suite 1000
                  Houston, Texas 77067-4525
                  Phone:  281-874-0035
                  Fax:  281-775-8414
                  Attention:  Jordan "Digger" Smith
                  Telephone:  281-874-0035
                  Fax:  281-874-8414

                  WITH A COPY TO:

                  Law Dept of Nabors Corporate Services, Inc.
                  515 W. Greens Road, Suite 1200
                  Houston, Texas 77067-4525?
                  Phone number is 281-874-0035
                  Fax:  281-775-8431

         9.3 Binding Effect. This Agreement shall bind and inure to the benefit
of successors in interest and assigns of El Paso and Ramshorn.



                                       24
<PAGE>


         9.4 GOVERNING LAW. THE VALIDITY, EFFECT AND CONSTRUCTION OF THIS
AGREEMENT SHALL BE GOVERNED BY THE LAWS OF THE STATE OF TEXAS WITHOUT GIVING
EFFECT TO ITS CONFLICTS OF LAWS PROVISIONS, EXCEPT WHERE THE LAWS OF ANOTHER
JURISDICTION ARE MANDATORILY APPLICABLE WITH RESPECT TO THE CONVEYANCE OF THE
NET OVERRIDING ROYALTY INTEREST.

         9.5 Headings. Article and Section headings used in this Agreement are
for convenience only and shall not affect the construction of this Agreement.

         9.6 Intention of the Parties.

                  (a) Nothing herein contained is intended to create, nor shall
the same be construed as creating (under state law or for tax purposes), any
mining partnership, commercial partnership or other partnership relation or
joint venture. If, however, the parties hereto are deemed to constitute a
partnership for federal or state income tax purposes, the parties elect to be
excluded from the application of Subchapter K, Chapter 1, Subtitle A of the Code
(or any similar state law) and agree not to take any position inconsistent with
such election.

                  (b) In addition, the parties hereto intend that the Net
Overriding Royalty Interest conveyed hereby by El Paso to Ramshorn shall at all
times be treated as a non-operating "economic interest" in the Oil and Gas
within the meaning of the Code (or any corresponding provisions of succeeding
law) and a non-operating mineral right for state law purposes. It is further
intended that the Assignment(s) of Overriding Royalty Interest contemplated
hereunder constitutes a present, absolute and indefeasible conveyance of a real
property interest (fee simple determinable) in Texas and other common law
jurisdictions and of an immovable property right in Louisiana. Nothing herein
shall suggest, nor shall anything herein be construed to suggest, that the
purchase and sale transactions contemplated herein constitute one or more
financing transactions. However, for the avoidance of doubt, Ramshorn shall be
entitled to file a copy of the Memorandum of Purchase and Sale Agreement as a
precautionary UCC non-standard financing statement to better evidence and
perfect its interest in the Net Profits, Net Overriding Royalty Interest, the
After Payout Overriding Royalty Interest, the Oil and Gas attributable thereto
and the proceeds thereof.

         9.7 Counterpart Execution. This Agreement may be executed in multiple
counterparts, each of which shall be deemed an original agreement for all
purposes hereunder.

         9.8 Validity and Severability. If any provision of this Agreement is
held to be illegal, invalid or unenforceable under the present or future laws
effective during the term of this Agreement, such provision shall be fully
severable; this Agreement shall be construed and enforced as if such illegal,
invalid or unenforceable provision had never comprised a part of this Agreement;
and the remaining provisions of this Agreement shall remain in full force and
effect and shall not be affected by the illegal, invalid or unenforceable
provision or by its severance from this Agreement. In lieu of such illegal,
invalid or unenforceable provisions, there shall be added automatically as a
part of this Agreement a provision as similar in terms to such illegal, invalid
or unenforceable provision as may be possible and be legal, valid and
enforceable.



                                       25
<PAGE>


         9.9 Negotiated Instrument. This Agreement represents a negotiated
agreement and no portion shall be construed for or against either party by
virtue of its having been drafted by that party.

         9.10 Securities Act. Ramshorn (i) understands that the Net Overriding
Royalty Interest has not been, and will not be, registered under the Act, or
under any state securities laws, and is being offered and sold in reliance upon
certain federal and state exemptions, (ii) is acquiring the Net Overriding
Royalty Interest solely for Ramshorn's own account for investment purposes, and
not with a view to the public distribution thereof, (iii) is a sophisticated
investor with knowledge and experience in business and financial matters, (iv)
has received certain information concerning the Net Overriding Royalty Interest
and has had the opportunity to obtain additional information as desired to
evaluate the merits and the risks inherent in purchasing the Net Overriding
Royalty Interest, (v) is able to bear the economic risk and lack of liquidity
inherent in holding the Net Overriding Royalty Interest, and (vi) is an
"accredited investor" as defined in Regulation D promulgated under the Act.

         9.11 Amendments. Any amendment hereto shall become effective only upon
the express written consent of El Paso and Ramshorn, at which time it shall
become effective as to all parties hereto. No amendment, modification or
alteration of the terms hereof shall be binding unless the same is in writing
and is in accordance with this Section 9.11.

         9.12 Confidentiality. Notwithstanding anything herein to the contrary,
the parties (and each employee, representative or other agent of El Paso or
Ramshorn) may disclose to any and all Persons, without limitation of any kind,
the U.S. federal income tax treatment and tax structure of the transaction
contemplated herein and all materials of any kind (including opinions and other
tax analyses) that are provided to the parties relating to such tax treatment
and tax structure. For this purpose, "tax structure" is limited to facts
relevant to the U.S. federal income tax treatment of such transaction and does
not include information relating to the identity of the parties, their
respective Affiliates, agents or advisors.

         9.13 Benefits of Agreement Restricted to Parties. Nothing in this
Agreement expressed or implied is intended or shall be construed to give to any
Person other than El Paso and Ramshorn, and their respective successors and
assigns, any legal or equitable right, remedy or claim under or in respect of
this Agreement or any covenant, condition or provision therein or herein
contained; and all such covenants, conditions and provisions are and shall be
held to be for the sole and exclusive benefit of El Paso and Ramshorn, and their
respective successors and assigns.

         9.14 Exhibits.

                  (a) The forms of instruments attached hereto as Exhibit "D-1"
through "G-2" are prepared for use in connection with Subject Wells drilled by
El Paso Production Company. With respect to Subject Wells drilled by El Paso
Production GOM Inc., such forms shall be identical in all respects except with
such changes thereto, mutatis mutandi, as are appropriate to reflect the
substitution of El Paso Production GOM Inc. for El Paso Production Company as
the El Paso party thereto.



                                       26
<PAGE>


                  (b) In order to satisfy the requirements of the Louisiana
public records doctrine and other related Louisiana laws, the parties have
contemporaneously executed a Declaration and Agreement in the form attached
hereto as Exhibit "H", which shall be recorded in each parish in Louisiana where
any lands covered by Subject Leases are located. As among the parties hereto,
such Declaration and Agreement shall be deemed a part of, and subsumed within
and under, this Agreement, it being the parties' express understanding and
intention that as among the parties, such Declaration and Agreement shall not
create, and shall not be construed to create, any additional rights or
obligations beyond those provided for or created herein or hereunder nor shall
such Declaration and Agreement limit, expand, alter or in any other way affect
any such rights or obligations; and the parties acknowledge and agree that as
among themselves, this Agreement alone shall govern the transactions
contemplated herein.

         9.15 Liability of Ramshorn. In no event shall Ramshorn be personally
liable or responsible in any way for payment of any part of the costs, expenses
or liabilities incurred in connection with the exploring, developing, operating
and maintaining of the Subject Leases or the Subject Wells, and El Paso agrees
to indemnify and hold Ramshorn harmless from and against all such costs,
expenses or liabilities; provided, however, all costs and expenses described in
this Section 9.15 shall, to the extent the same relate to the period prior to
the Payout Date, nevertheless be charged against the Net Profits Account to the
extent herein permitted.

Executed the date first written above.

                                              EL PASO PRODUCTION COMPANY

                                              By: /s/ John T. Elzner
                                                  ------------------------------
                                                  John T. Elzner, Senior Vice
                                                  President


                                              EL PASO PRODUCTION GOM INC.

                                              By: /s/ John T. Elzner
                                                  ------------------------------
                                                  John T. Elzner, Senior Vice
                                                  President


                                              RAMSHORN INVESTMENTS, INC.

                                              By: /s/ Jordan "Digger" Smith
                                                  ------------------------------
                                                  Jordan "Digger" Smith,
                                                  President



                                       27


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.24
<SEQUENCE>4
<FILENAME>h13476exv10w24.txt
<DESCRIPTION>PURCHASE AND SALE AGREEMENT
<TEXT>
<PAGE>


                                                                   EXHIBIT 10.24


                           PURCHASE AND SALE AGREEMENT
                                      (USA)

         This Purchase and Sale Agreement (this "Agreement") is entered into
this 8th day of October, 2003, by and among EL PASO PRODUCTION OIL & GAS USA,
L.P. ("El Paso") and RAMSHORN INVESTMENTS, INC. ("Ramshorn").

         WHEREAS, Ramshorn desires to purchase an overriding royalty interest in
the Subject Leases INSOFAR and ONLY INSOFAR as the Subject Leases cover the
Subject Wells drilled and completed thereon and the Oil and Gas produced
therefrom, all as set forth herein; and

         WHEREAS, El Paso desires to drill and complete the Subject Wells;

         NOW THEREFORE, in consideration of the terms and provisions of this
Agreement, the adequacy of which is hereby acknowledged, El Paso and Ramshorn
agree as follows:

                                    ARTICLE I
                                   DEFINITIONS

         1.1 Capitalized Terms. As herein used the following words, terms or
phrases have the following meanings:

         "Act" is defined in Section 5.1.

         "AFE" means an authority for expenditure, which is a good faith
estimate prepared by El Paso of the costs of an operation, which may include a
ten percent (10%) contingency amount. An AFE to drill a new well has an
estimated cost to drill and plug and abandon a well if it is a dry hole and the
cost to complete the well.

         "Affiliate" means with respect to any Person ("first Person") any
Person (i) which controls either directly or indirectly such first Person, or
(ii) which is controlled directly or indirectly by such first Person, or (iii)
is directly or indirectly controlled by a Person which directly or indirectly
controls such first Person. "Control" in the case of a Person which is a
corporation means the right to exercise 50% or more of the voting rights in the
appointment of the board of directors, or other body performing similar
functions, of such Person.

         "After Payout Overriding Royalty Interest" is defined in Section
2.5(b).

         "Agents" is defined in Section 6.5.

         "Agreed Rate" means a rate equal to the rate of interest per annum
publicly announced from time to time by JPMorgan Chase Bank as its prime rate in
effect at its principal office in New York, New York on the first day of the
month in which a payment delinquency under Section 3.3 occurs, plus 1.00%.

         "Agreement" is defined in the preamble hereto.



<PAGE>


         "Alternate Well" is defined in Section 2.9.

         "Approved Independent Engineer" means Huddleston & Co. Inc. or another
independent petroleum engineer of recognized national standing selected by El
Paso and acceptable to Ramshorn, in its reasonable discretion.

         "Business Day" means any day of the year that is not a Saturday, Sunday
or other day in which commercial banks are authorized or required to remain
closed in Houston, Texas or New York, New York.

         "Cash Method of Accounting" means a method of accounting in which (i)
the Gross Proceeds for a month shall be the net amount recognized and recorded
during such month in El Paso's ledgers for sales of Oil and Gas produced from
the relevant wells and (ii) the Production Costs for a month shall be the net
amount paid or charged to the relevant wells by El Paso and recorded during such
month in El Paso's ledgers. Accordingly, by way of example only, sales of
January production of Oil and Gas will normally be used to determine Gross
Proceeds for the month of March.

         "Code" means the Internal Revenue Code of 1986, as amended.

         "Dry Well" means a Subject Well that has been drilled and then plugged
and abandoned as a dry hole.

         "El Paso" is defined in the preamble hereto.

         "Encumbrance" means any (i) mortgage, lien, security interest, pledge,
encumbrance or claim or (ii) royalty, overriding royalty, production payment,
net profits interest or like burden on, or prepaid or forward Sales Contract
covering, the Oil and Gas produced from any Subject Well.

         "Excess Production Costs" means, for any month, the amount of
Production Costs (plus any Excess Production Costs carried forward from a prior
month) in excess of Gross Proceeds for such month.

         "Gross Proceeds" means, for any month, the amount received on the Cash
Method of Accounting by El Paso, without duplication, from the Sale of Oil and
Gas produced from Subject Wells, subject to the following:

                  (a) If any gas is processed before the sale thereof, the
amount of the Gross Proceeds for such gas shall be the gross proceeds from the
sale of El Paso's proportionate share of the residue gas and liquid hydrocarbons
attributable to the processed gas as determined by the processing agreement, if
any, covering such gas or, if there is no gas processing agreement in place, the
amount of proceeds for such gas shall be the gross proceeds from the sale of El
Paso's proportionate share of the wellhead volume multiplied by the Btu content.

                  (b) There shall be excluded any amount for Oil and Gas
attributable to non-consent operations conducted with respect to any Subject
Well as to which El Paso shall be a non-consenting party and which is dedicated
to the recoupment or reimbursement of costs and



                                       2
<PAGE>


expenses of the consenting party or parties by the terms of the relevant
operating agreement, unit agreement, contract for development or other agreement
providing for such non-consent operations. Similar amounts received by El Paso
from non-consenting third parties shall be included in Gross Proceeds.

                  (c) If for any reason any purchaser or any other third party
withholds payment for any sales volume or El Paso's proportionate share thereof
of any Oil and Gas produced from a Subject Well, then amounts withheld by the
purchaser or any such third party shall not be considered to be received by El
Paso or part of the Gross Proceeds until actually collected by El Paso or El
Paso receives the production therefrom, but any interest, penalty or other
amount paid to El Paso in respect thereof shall be included in Gross Proceeds.

                  (d) Gross Proceeds shall not include the value of any Oil and
Gas unavoidably lost or used in operations on any Subject Well and plant
operations (including gas injection, compression, treating, transporting,
secondary recovery, pressure maintenance, repressuring, recycling operations,
plant fuel or shrinkage).

                  (e) There shall be excluded from Gross Proceeds any valid and
existing royalties, overriding royalties, production payments, and like burdens
on the Oil and Gas produced from the Subject Wells of record on or before
September 1, 2003; provided, however, if El Paso acquires an additional interest
in a Subject Lease after such date, then all royalties, production payments, and
like burdens on such interest existing at the date of acquisition shall also be
excluded from Gross Proceeds.

                  (f) Subject to (b) above, there shall be excluded from Gross
Proceeds any revenues received by El Paso that are attributable to the net
revenue interests of other working interest owners of the Oil and Gas produced
from any Subject Well.

                  (g) There shall be excluded from Gross Proceeds any amounts
received by El Paso from a purchaser of Oil and Gas as advance payments and
payments pursuant to take-or-pay and similar provisions of Sales Contracts until
such Oil and Gas is actually produced and delivered to such purchaser. When such
Oil and Gas is produced, then the market value of such Oil and Gas at the time
of such production shall be included in Gross Proceeds.

                  (h) During any month when El Paso is, for any Subject Well, an
Overproduced Party or an Underproduced Party under any gas balancing
arrangement, there shall be included in Gross Proceeds amounts received by El
Paso from a purchaser of Oil and Gas or an Overproduced Party as and when paid
to El Paso and when El Paso is required to make settlement in cash for any net
overproduction, such payment shall be deducted from the Gross Proceeds, if any.

                  (i) To the extent allocable to the Subject Wells, refunds of
revenues previously included as Gross Proceeds for such Subject Well required to
be made by El Paso (including any interest thereon or penalties) as a result of
the bankruptcy, insolvency or similar condition of a purchaser of production or
other party, an order of the Federal Energy Regulatory Commission, tax, or other
governmental unit or any other legal reason shall be deducted from Gross
Proceeds.



                                       3
<PAGE>


                  (j) To the extent allocable to a Subject Well, any amounts
paid in good faith by El Paso as a prudent owner or operator, whether as refund,
interest or penalty, to a purchaser because the amount initially received by El
Paso as the sales price attributable to Oil and Gas produced was more or
allegedly more than permitted by the terms of any applicable contract, statute,
regulation, order, decree or other obligation shall be deducted from Gross
Proceeds.

                  (k) Insurance proceeds received by El Paso relating to any
Subject Well shall be included in Gross Proceeds if such proceeds relate to
equipment or other property, the costs which were included in Investment Costs
or Production Costs.

                  (l) Proceeds of the sale of any equipment or other property
shall be included in Gross Proceeds if the original cost thereof was included as
an Investment Cost or a Production Cost.

                  (m) Net damages, after deducting court costs, expert fees,
attorney fees and other litigation costs, collected by El Paso and attributable
to a Subject Well in any litigation covering damage to reserves or reservoir
formations shall be included in Gross Proceeds.

                  (n) Proceeds of the sale of Permitted Third Party Net Profits
Interests shall not be included in Gross Proceeds.

         "Investment Costs" means the actual costs incurred on a Subject Well of
drilling, completing, equipping (including but not limited to flow lines, tanks,
and related equipment) to the point of product sales, and plugging and
abandoning (if a Subject Well was a dry hole) and the cost of recompleting to
another zone, deepening, side-tracking, or plugging and abandoning a well and
any other costs considered to be capital costs (and not expenses) under U.S.
generally accepted accounting principles, whether such costs were incurred
before or after the date of this Agreement.

         "Investment Invoice" is defined in Section 2.3.

         "Investment Percentage" is defined in Section 2.1.

         "Net Overriding Royalty Interest" is defined in Section 2.1.

         "Net Profits" means, for the Subject Wells for any month, the excess of
aggregate Gross Proceeds for such month over the sum of (i) aggregate Production
Costs for such month and (ii) aggregate Excess Production Costs as of the end of
the immediately preceding month, all on the Cash Method of Accounting.

         "Net Profits Account" is defined in Section 3.4.

         "Oil and Gas" means oil, gas, other liquid and gaseous hydrocarbons.

         "Overproduced Party" means a party to a gas balancing arrangement who,
as a result of producing, in addition to its own share of production, that
portion of another party's share of production which such other party is unable
or unwilling to market or otherwise to dispose of, is



                                       4
<PAGE>


in a position of net overproduction with respect to such other party or parties
to such gas balancing arrangement.

         "Payout Account" is defined in Section 2.4.

         "Payout Date" means the first day after the Project Completion Date on
which the balance in the Payout Account is equal to or less than zero.

         "Permitted Encumbrances" means any or all of the following:

                  (a) Encumbrances that arise under operating agreements to
secure payment of amounts not yet delinquent and are of a type and nature
customary in the oil and gas industry;

                  (b) Encumbrances that arise as a result of pooling and
unitization agreements, designations, declarations, orders or laws;

                  (c) Encumbrances securing payments to mechanics and
materialmen and Encumbrances securing payment of taxes or assessments that are,
in either case, not yet delinquent or, if delinquent, are being contested in
good faith in the normal course of business;

                  (d) consents to assignment by governmental authorities that
are customarily obtained after the consummation of transactions of the nature
contemplated by this Agreement;

                  (e) conventional rights of reassignment obligating El Paso to
reassign its interest in any portion of the Subject Leases to a third party in
the event El Paso intends to release or abandon such interest prior to the
expiration of the primary term or other termination of such interest;

                  (f) easements, rights-of-way, servitudes, permits, surface
leases, surface use restrictions and other surface uses and impediments on, over
or in respect of any of the Subject Leases that are not such as to interfere
materially with the operation, value or use of the Subject Leases, taken as a
whole;

                  (g) calls on or preferential rights to purchase production at
not less than market prices prevailing in the field, held by parties other than
El Paso or Affiliates of El Paso;

                  (h) such Encumbrances as Ramshorn has expressly waived in
writing;

                  (i) royalties, overriding royalties, production payments, and
like burdens on the Oil and Gas produced from any Subject Well existing of
record as of September 1, 2003;

                  (j) rights reserved to or vested in any municipality or
governmental, tribal, statutory or public authority to control or regulate any
of the Subject Leases in any manner, and all applicable laws, rules and orders
of any municipality or governmental or tribal, statutory or public authority;

                  (k) the terms and conditions of the Subject Leases;



                                       5
<PAGE>


                  (l) division orders and Sales Contracts terminable without
penalty upon no more than ninety (90) days' notice to the purchaser;

                  (m) preferential rights and required third party consents to
assignment and similar agreements with respect to which waivers or consents are
obtained from the appropriate parties, or the appropriate time period for
asserting any such right has expired without an exercise of the right;

                  (n) Permitted Third Party Net Profits Interests; and

                  (o) all other liens, charges, encumbrances, contracts,
agreements, instruments, obligations, defects and irregularities affecting the
Subject Leases that individually or in the aggregate are not such as to
materially interfere with the operation, value or use of any of the Subject
Wells and do not prevent Ramshorn from receiving its proportionate share of the
Net Profits before the Payout Date and after the Payout Date, the proceeds of
its After Payout Overriding Royalty Interest.

         "Permitted Third Party Net Profits Interests" means net profits
interests or net overriding royalty interests sold by El Paso to non-Affiliates
conveying an interest in Net Profits attributable to some or all of the Subject
Wells; provided, however, the total interest in Net Profits represented by all
Permitted Third Party Net Profits Interests and the Net Overriding Royalty
Interest shall not exceed seventy percent (70%); and provided further, however,
that the agreements, conveyances or other instruments creating, granting or
evidencing any such interests do not create or result in, or purport to create
or result in any priority over, or any rights whatsoever senior to, the rights
and interests of Ramshorn hereunder or under any conveyance or other instrument
executed by El Paso pursuant hereto.

         "Person" means any individual, corporation, partnership, trust, estate
or other entity or organization.

         "Present Value" means, for purposes of any purchase by El Paso from
Ramshorn pursuant to Section 5.3(a), the present value of the Net Overriding
Royalty Interest in the applicable Subject Well applying a ten percent (10%)
discount rate to the undiscounted future pre-tax net cash flows accruing to such
interest, minus all projected undiscounted future Investment Costs associated
therewith, as shown on the most current Reserve Report, from the effective date
of such purchase to the projected Payout Date and in the case of the After
Payout Overriding Royalty Interest into which such interest shall convert at the
Payout Date, the undiscounted future pre-tax net cash flows accruing to such
interest, as shown on the most current Reserve Report, from the projected Payout
Date to ultimate depletion of the Subject Well(s) burdened thereby.

         "Production Costs" for a month means, to the extent such costs are
allocable to El Paso's working interest in the Subject Wells and have been paid
by El Paso or charged by El Paso to such wells during such month under the Cash
Method of Accounting, without duplication:

                  (a) The sum of:



                                       6
<PAGE>


                           (i) costs of labor charged to the Subject Wells
         including salaries and wages, employee benefits, and miscellaneous
         employee costs provided for:

                              (1) field employees directly engaged in the
                    operation of any such well;

                              (2) first level supervisors engaged in the
                    supervision of the operation of any such well;

                              (3) technical employees employed on any such well
                    if such charges are not included in the per-well overhead
                    rates referred to below in subparagraph (iii) of this
                    paragraph (a) and not otherwise charged; and

                              (4) employees of shore bases or other facilities
                    serving any such well if such charges are not included in
                    the per-well overhead rates referred to below in
                    subparagraph (iii) of this paragraph (a) and not otherwise
                    charged.

                           (ii) other direct costs allocated to the Subject
         Wells not reimbursed by applicable insurance including:

                              (1) contract and professional services;

                              (2) materials, supplies, fuel, water, and treating
                    chemicals;

                              (3) salt water disposal;

                              (4) well and leasehold equipment repairs and
                    maintenance, including workovers;

                              (5) transportation including boats, aircraft, and
                    other vehicles;

                              (6) costs paid by El Paso, as the operator, for
                    dehydration, compression, separating, treating, storing,
                    gathering, and gas transportation of Oil and Gas to the
                    point of product sales;

                              (7) safety and environmental costs, including
                    spill cleanup, except for such costs attributable to El
                    Paso's gross negligence or willful misconduct;

                              (8) the costs of secondary recovery, pressure
                    maintenance, repressuring, recycling, and other operations
                    used to enhance production of Oil and Gas to the point of
                    product sales;

                              (9) to the extent directly allocable to a Subject
                    Well, (i) insurance including workman's compensation,
                    general liability, and (ii) the costs of certificates of
                    responsibility, performance bonds or letters of credit;



                                       7
<PAGE>
                              (10) other miscellaneous costs of operating,
                    producing, and maintaining a Subject Well for services or
                    supplies furnished by or on behalf of El Paso, as the
                    operator, which is of direct benefit to such well and
                    incurred in the necessary and proper conduct of operations
                    thereon, and which normally would be chargeable by an
                    operator to the "joint account" under a customary joint
                    operating agreement for similar wells; and

                              (11) costs incurred for claims, demands or
                    litigation relating to property damage, including
                    environmental damages, spills, clean-up and remediation,
                    personal injury or death, or claims, demands or litigation
                    brought by third parties, including governmental or
                    regulatory authorities except for such costs attributable to
                    El Paso's gross negligence or willful misconduct.

                           (iii) per well overhead in accordance with the
         provisions of the joint operating agreement accounting procedure
         covering a Subject Well or if none exists for a Subject Well, Section
         III of the accounting procedures attached hereto as Schedule I
         (Onshore) or Schedule II (Offshore), as applicable.

                           (iv) an amount equal to all general property (ad
         valorem), production, severance, sales, gathering, energy, BTU and
         similar state, federal, or other taxes (except income taxes) assessed
         or levied on or in connection with the Subject Wells, the Net
         Overriding Royalty Interest, or the production therefrom or equipment
         thereon or associated therewith, and which taxes (as adjusted or
         finally determined) are deducted or excluded from proceeds from the
         sale of Oil and Gas received by El Paso or paid by El Paso and
         attributable to both El Paso's and Ramshorn's share in the Oil and Gas;
         provided however, that if Ramshorn bears any such taxes individually,
         such taxes will not be considered to constitute Production Costs.

                  (b) Where production costs incurred for the benefit of a
Subject Well also benefit other wells or properties, El Paso will allocate
charges on an equitable and consistent basis.

                  (c) Production Costs for the Subject Wells shall not include:

                           (i) general and administrative costs that are not
         covered by the joint operating agreement accounting procedure covering
         a Subject Well or if none exists for a Subject Well, Section III of the
         accounting procedures attached hereto as Schedule I (Onshore) or
         Schedule II (Offshore), as applicable;

                           (ii) depreciation, depletion, or amortization; or

                           (iii) any payments to holders of Permitted Third
         Party Net Profits Interests.

                  (d) Any increased costs or liabilities that are borne by El
Paso as a result of its being a consenting party in non-consent operations on a
Subject Well shall be deemed to be allocable to or applicable to such Subject
Well.



                                       8
<PAGE>


                  (e) Production Costs shall include costs incurred after the
expiration of the Project Term with respect to operations on Subject Wells
notwithstanding that such costs may be properly characterized as capital costs
under U.S. generally accepted accounting principles.

         "Project Completion Date" is defined in Section 2.7.

         "Project Term" is defined in Section 8.2. Where the context requires,
references herein to the "Project Term" shall be deemed to be references to the
"Revised Project Term" as defined in Section 8.3.

         "Reserve Report" means any reserve report described in Section 6.6.

         "Sale" means and includes sales, assignments, transfers, exchanges and
other dispositions for value.

         "Sales Contract(s)" means all contracts and agreements for the offer or
sale of, or commitment to offer or sell, or right of first refusal to purchase,
Oil and Gas after production.

         "Subject Lease" or "Subject Leases" means the oil, gas and mineral
leases described in Exhibit "B" attached hereto as such Exhibit may be amended
from time to time as provided herein, including extensions and renewals of any
such lease obtained within six (6) months of the expiration thereof.

         "Subject Well" or "Subject Wells" means the oil and gas wells described
in Exhibit "A" attached hereto as such Exhibit may be amended from time to time
as provided herein.

         "Substitute Well" is defined in Section 2.8.

         "Underproduced Party" means a party to a gas balancing arrangement who,
as a result of its inability or unwillingness to market or otherwise dispose of
a portion of its share of production and another party's producing such share of
production, is in a position of net underproduction with respect to such other
party or parties to such gas balancing arrangement.

         "Well Cost Adjustment" means the difference, if any, between the
completed well cost as reflected in an AFE for a Subject Well and the actual
Investment Costs of such Subject Well (including costs which were not
contemplated in the AFE such as capital costs that are incurred after a well has
produced) as determined from time to time when the actual costs are determined;
provided, however, for purposes of determining any Well Cost Adjustment, no
Investment Cost incurred by El Paso after expiration of the Project Term will be
considered or included, and any such cost (regardless of its proper
characterization under U.S. generally accepted accounting principles) will be
considered and included as a Production Cost. The Well Cost Adjustment shall be
a positive number if the actual Investment Costs are higher than the AFE costs
and a negative number if the actual Investment Costs are lower than the AFE
costs.



                                       9
<PAGE>


                                   ARTICLE II
                                PURCHASE AND SALE

         2.1 Acquired Assets. Subject to the terms and conditions of this
Agreement, El Paso agrees to sell, convey and deliver to Ramshorn and Ramshorn
agrees to purchase and acquire from El Paso, subject to an after payout
conversion as provided for in Section 2.5(b), an overriding royalty interest in
the Subject Leases INSOFAR and ONLY INSOFAR as the Subject Leases cover the
Subject Wells and the Oil and Gas produced therefrom equal to the amount of the
Investment Percentage multiplied by the Net Profits from all the Subject Wells
(the "Net Overriding Royalty Interest"). The "Investment Percentage" shall be
twenty percent (20%), subject to adjustment as provided in Section 8.3.

         2.2 Purchase Price. The purchase price for the Net Overriding Royalty
Interest is the Investment Percentage of the amount of El Paso's proportionate
share (based upon El Paso's working interest in each Subject Well) of the total
Investment Costs of the Subject Wells commenced during the Project Term, and
which were incurred on or before the Project Completion Date.

         2.3 Payment of Purchase Price.

                  (a) By the last Business Day of each month, El Paso shall
invoice Ramshorn (an "Investment Invoice") for an amount equal to the Investment
Percentage of the sum of (i) the total of the estimated "Drill" costs as shown
in the AFE for each Subject Well commenced in the prior month multiplied by El
Paso's working interest in each such Subject Well, (ii) the total of the
estimated "Complete" and "Facilities" costs for each Subject Well on which El
Paso intends to commence completion operations in the following month or for
which completion operations have commenced plus (iii) any Investment Costs for
any operations on a Subject Well not contemplated in the AFE for drilling and
completing such Subject Well, but reasonably and directly related to, or
required in furtherance of, the specific drilling operation described in such
AFE, multiplied by El Paso's working interest in each such Subject Well, plus or
minus (iv) any Well Cost Adjustment on any Subject Well that had been determined
in the prior month multiplied by El Paso's working interest in such Subject
Well. The Investment Invoice shall not include any amount for the estimated
completed well costs as shown in the AFE for drilling and completing a Subject
Well commenced after the expiration of the Project Term or Investment Costs
incurred after the Project Completion Date.

                  (b) If an Investment Invoice is for a negative amount, then
the Payout Account shall be reduced by an amount equal to such amount multiplied
by one hundred seventeen and a half percent (117.5%) and El Paso shall pay to
Ramshorn the amount of such Investment Invoice with El Paso's next payment of
the Net Overriding Royalty Interest as provided in Section 3.2.

         2.4 Payout Account. The amount of all payments by Ramshorn for
Investment Invoices plus an additional 17.5% shall be credited to Ramshorn in an
account for all Subject Wells maintained by El Paso (the "Payout Account"),
which will be used to determine when all of the Net Overriding Royalty Interest
purchased by Ramshorn shall be suspended pursuant to Section 2.7 or converted
pursuant to Section 2.7(c). For example, if an AFE for drilling a



                                       10
<PAGE>


Subject Well is for $1,000,000 and El Paso's working interest is 100%, then El
Paso shall invoice Ramshorn for $200,000 and, upon payment of the invoice,
$235,000 shall be credited to the Payout Account. If an AFE for drilling a
Subject Well is for $1,000,000 and El Paso's working interest is 50%, then El
Paso shall invoice Ramshorn for $100,000 and, upon payment of the invoice,
$117,500 shall be credited to the Payout Account.

         2.5 Conveyance of Net Overriding Royalty Interest; Conversion.

                  (a) Within five (5) days after El Paso receives payment from
Ramshorn for an Investment Invoice, El Paso shall execute and deliver to
Ramshorn a recordable assignment substantially in the form attached hereto as
Exhibit "D-1" (for recordation in Texas) or "D-2" (for recordation in Louisiana)
of the Net Overriding Royalty Interest in the Subject Leases INSOFAR and ONLY
INSOFAR as the Subject Leases cover the Subject Wells whose drilling and
completion AFE was covered by such Investment Invoice and the Oil and Gas
produced therefrom. Each such assignment shall identify each Subject Well
covered thereby by name, location and API number.

                  (b) The Net Overriding Royalty Interest shall automatically
convert on the Payout Date into a perpetual overriding royalty interest in the
Subject Leases INSOFAR and ONLY INSOFAR as the Subject Leases cover the Subject
Wells that were covered by the Net Overriding Royalty Interest and the Oil and
Gas produced therefrom equal to the Investment Percentage (at the time of
conversion) times two percent (2%) of 8/8ths (the "After Payout Overriding
Royalty Interest"). The After Payout Overriding Royalty Interest shall be
proportionately reduced on a lease-by-lease basis, as follows:

                           (i) If El Paso owns less than the entire oil and gas
         leasehold estate created by any Subject Lease, the After Payout
         Overriding Royalty Interest shall be paid in the proportion which the
         fractional part of such leasehold estate owned by El Paso bears to the
         entire oil and gas leasehold estate created by such Subject Lease;

                           (ii) If any Subject Lease covers less than the entire
         oil and gas estate, the After Payout Overriding Royalty Interest shall
         be paid in the proportion which the fractional part of the oil and gas
         estate covered by the Subject Lease bears to the entire oil and gas
         estate; and

                           (iii) If any Subject Lease, or any part thereof, is
         pooled or unitized in a unit, the After Payout Overriding Royalty
         Interest shall be paid in the proportion that the acreage covered by
         the Subject Lease included in such unit bears to all the acreage
         included in such unit.

                  (c) After the Payout Date and within thirty (30) days from a
request by El Paso, Ramshorn shall execute and deliver to El Paso a Notice of
Conversion and Reconveyance of Overriding Royalty Interest in the form attached
hereto as Exhibit "E-1" (for recordation in Texas) and "E-2" (for recordation in
Louisiana) and return any data or materials acquired by Ramshorn pursuant to
this Agreement.

                  (d) If all of the Subject Wells are not commenced prior to the
end of the Project Term, El Paso shall continue to assign Ramshorn its Net
Overriding Royalty Interest in



                                       11
<PAGE>


each such Subject Well until the Payout Date. After the Payout Date, El Paso
shall not be obligated to assign Ramshorn any additional Net Overriding Royalty
Interests in Subject Leases or Subject Wells even as to Subject Wells commenced
prior to the Payout Date, but after the Project Term.

                  (e) If a Subject Well is plugged and abandoned, then at El
Paso's request Ramshorn shall execute and deliver to El Paso a Partial
Reconveyance and Termination of Overriding Royalty Interest in the form attached
hereto as Exhibit "F-1" (for recordation in Texas) or "F-2" (for recordation in
Louisiana) but limited to the Net Overriding Royalty Interest in such Subject
Well.

                  (f) Ramshorn shall not have the right or option to take in
kind any Oil or Gas attributable to the Net Overriding Royalty Interest or the
After Payout Overriding Royalty Interest.

          2.6 Memorandum of Purchase and Sale Agreement. El Paso shall
contemporaneously with the execution of this Agreement execute and file of
record, in each county in Texas wherein any lands covered by any Subject Lease
are located, a Memorandum of Purchase and Sale Agreement in the form attached
hereto as Exhibit "C." In lieu thereof, in each parish in Louisiana wherein any
lands covered by any Subject Lease are located, El Paso will file of record a
fully executed and properly witnessed original counterpart of a Declaration and
Agreement, in the form attached hereto as Exhibit "H.".

          2.7 Suspension of the Net Overriding Royalty Interest. Until the date
all of the Subject Wells commenced before the end of the Project Term have been
drilled, completed, and equipped or determined to be a Dry Well (the "Project
Completion Date"), Ramshorn's right to receive payment from the Net Overriding
Royalty Interest for all of the Subject Wells shall be suspended from time to
time whenever the amount in the Payout Account is equal to or less than zero.
Any Net Profits during such suspensions shall not be carried forward and El Paso
shall be entitled to keep such Net Profits. During such suspension of the Net
Overriding Royalty Interest, the Net Profits for the Subject Wells shall be
deemed to be zero. Such suspension(s) shall automatically cease when the amount
in the Payout Account is again greater than zero.

          2.8 Substitute Wells. In the event granite, salt, saltwater flow,
heaving shale or other conditions, including either the loss of the hole or
mechanical difficulties, are encountered in the drilling or completing of a
Subject Well drilled pursuant to the terms of this Agreement which would render
further operations impracticable in the opinion of El Paso, El Paso has the
right but not the obligation under this Agreement to commence the actual
drilling of a "Substitute Well", at a legal location to the same target
objective as the Subject Well after the plugging and abandoning of the Subject
Well during the period this Agreement is in place. Such Substitute Well shall
become a Subject Well and any reference to the Subject Wells shall include such
Substitute Well.

          2.9 Alternate Wells.

                  (a) If El Paso elects not to drill a Subject Well because (i)
of title, permitting, or logistical problems, or (ii) the results from drilling
prior wells or the acquisition, evaluation, of



                                       12
<PAGE>


additional geological, geophysical or other information eliminated such Subject
Well as a well El Paso desires to drill because such results were negative, then
El Paso may replace such Subject Well with an alternate well or wells
("Alternate Well(s)") described on Exhibit "A" attached hereto and made part
hereof. Such Alternate Well(s) shall become Subject Well(s) and any reference to
Subject Well(s) shall include such Alternate Well(s).

                  (b) In addition, if El Paso proposes to sell or otherwise
transfer a Subject Lease or Leases to a non-Affiliate in a bona fide, arm's
length transaction prior to the submission to Ramshorn of an Investment Invoice
related to the associated Subject Well(s) contemplated therefor, then El Paso
may replace such Subject Well with an Alternate Well. Such Alternate Well(s)
shall become Subject Well(s) and any reference to Subject Well(s) shall include
such Alternate Well(s).

                  (c) The Subject Wells and Alternate Wells are grouped in two
categories as shown on Exhibit "A." El Paso may replace Category 1 and 2 Subject
Wells with Category 1 Alternate Wells. El Paso may replace Category 2 Subject
Wells with Category 2 Alternate Wells. El Paso may replace Category 1 Subject
Wells with Category 2 Alternate Wells only with the consent of Ramshorn. El Paso
shall provide Ramshorn notice of any substitution pursuant to Section 2.7(a) in
the applicable Investment Invoice and notice of any substitution pursuant to
Section 2.7(b) not later than thirty (30) days prior to the proposed sale. Any
substitution of Alternate Well(s) for Subject Well(s) pursuant to Section 2.9(b)
shall be permitted only if the estimated ultimate reserves and total estimated
drilling and completion costs for the proposed Alternate Well(s) are
approximately equal to that of the Subject Well(s) for which El Paso has elected
to make a substitution under Section 2.9(b).

          2.10 Information About the Subject Wells. El Paso disclaims all
liability and responsibility for any representation, warranty (other than the
representations and warranties specifically set forth in this Agreement),
statements or communications (orally or in writing) to Ramshorn, including any
information contained in any opinion, information or advice that may have been
or in the future may be provided to Ramshorn by any employee, officer, director,
agent, consultant, engineer or engineering firm, trustee, representative,
partner, member, beneficiary, stockholder or contractor of El Paso wherever and
however made, including those made in any data room or internet site and any
supplements or amendments thereto or during any negotiations with respect to
this Agreement or any confidentiality agreement previously executed by El Paso
and Ramshorn with respect to the Subject Wells. EL PASO MAKES NO WARRANTY OR
REPRESENTATION, EXPRESS, STATUTORY OR IMPLIED, AS TO (i) THE ACCURACY,
COMPLETENESS OR MATERIALITY OF ANY DATA, INFORMATION OR RECORDS FURNISHED TO
RAMSHORN IN CONNECTION WITH THE SUBJECT WELLS, INCLUDING WITHOUT LIMITATION
SEISMIC DATA AND EL PASO'S INTERPRETATION AND OTHER ANALYSIS THEREOF; (ii) THE
PRESENCE, QUALITY AND QUANTITY OF HYDROCARBON RESERVES (IF ANY) ATTRIBUTABLE TO
THE SUBJECT WELLS; (iii) THE ABILITY OF THE SUBJECT WELLS TO PRODUCE
HYDROCARBONS, INCLUDING WITHOUT LIMITATION PRODUCTION RATES, DECLINE RATES AND
RECOMPLETION OPPORTUNITIES; (iv) ALLOWABLES OR OTHER REGULATORY MATTERS; (v) THE
PRESENT OR FUTURE VALUE OF THE ANTICIPATED INCOME, COSTS OR PROFITS, IF ANY, TO
BE DERIVED FROM THE SUBJECT WELLS; AND (vi) ANY PROJECTIONS. ANY DATA,



                                       13
<PAGE>


INFORMATION OR OTHER RECORDS FURNISHED BY EL PASO ARE PROVIDED TO RAMSHORN AS A
CONVENIENCE AND RAMSHORN'S RELIANCE ON OR USE OF THE SAME IS AT RAMSHORN'S SOLE
RISK.

          2.11 Independent Investigation. Ramshorn has made its own independent
investigation, analysis and evaluation of the transactions contemplated by this
Agreement (including Ramshorn's own estimate and appraisal of the extent and
value of the Oil and Gas reserves attributable to the Subject Wells and the
costs to explore for and develop the reserves if found). Prior to execution of
this Agreement, Ramshorn has had access to all information necessary to perform
its investigation and not relied on any representations by El Paso (other than
the representations specifically set forth in this Agreement). El Paso has
provided Ramshorn and its experts the opportunity to review El Paso's data on
the Subject Wells and Ramshorn has reviewed such data that it deems necessary.
Ramshorn understands and acknowledges that El Paso is not guaranteeing the
actual costs of vendors supplying services to the Subject Wells.

          2.12 Waiver of Deceptive Trade Practices Acts. RAMSHORN WAIVES ITS
RIGHTS UNDER THE DECEPTIVE TRADE PRACTICES ACT SECTION 17.41 et seq., TEXAS
BUSINESS & COMMERCE CODE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS, AND UNDER
SIMILAR STATUTES ADOPTED IN OTHER STATES, TO THE EXTENT THEY HAVE APPLICABILITY
TO THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. AFTER CONSULTATION WITH AN
ATTORNEY OF ITS SELECTION, RAMSHORN CONSENTS TO THIS WAIVER.

          2.13 Net Revenue Interest. El Paso represents and warrants that its
average aggregate ratio of net revenue interest to working interest for the
Subject Wells is not less than seventy percent (70%). Upon conversion of the Net
Overriding Royalty Interest as provided in Section 2.5(b), Ramshorn waives all
remedies for any breach of the foregoing representation.

          2.14 Encumbrances. El Paso represents and warrants that at the time
any Investment Invoice is submitted to Ramshorn for payment, and at the time the
related Assignment of Overriding Royalty Interest is filed of record in the
appropriate jurisdiction, the Subject Leases to which such invoice relates (to
the extent such leases contribute acreage for the Subject Well(s) to be drilled
thereon) shall be free and clear of any Encumbrances except Permitted
Encumbrances.

          2.15 Additional El Paso Representations and Warranties. El Paso hereby
represents and warrants to Ramshorn that:

                  (a) El Paso is a limited partnership, duly organized, validly
existing and in good standing under the laws of the State of Delaware, and has
all partnership power and all material governmental licenses, authorizations,
permits, consents and approvals required to carry on its business as now
conducted. El Paso is duly registered as a foreign limited partnership in the
State of Louisiana.

                  (b) The execution, delivery and performance by El Paso of this
Agreement and the performance by El Paso of its obligations hereunder are within
its partnership power and



                                       14
<PAGE>


have been duly authorized by all necessary action on the part of El Paso and by
all necessary action on the part of El Paso Production Oil & Gas Company in its
capacity as the general partner of El Paso. This Agreement constitutes a valid
and binding agreement of El Paso enforceable in accordance with its terms,
except as (i) the enforceability hereby may be limited by bankruptcy,
insolvency, moratorium or similar laws affecting the enforcement of creditors'
rights generally and (ii) the availability of equitable remedies may be limited
by equitable principles of general applicability.

                  (c) The execution, delivery and performance by El Paso of its
obligations hereunder do not and will not (i) contravene or conflict with the
certificate of limited partnership, the agreement of limited partnership, or any
other organizational documents of El Paso, (ii) contravene or conflict with or
constitute or default (without regard to any requirement of notice or the lapse
of time or both) any provision of any law, regulation, judgment, injunction,
order or decree binding upon or applicable to El Paso, or any indenture,
mortgage, lien, lease, agreement or instrument to which El Paso is a party or by
which it or any of its assets or properties are bound.

          2.16 Ramshorn Representations and Warranties. Ramshorn hereby
represents and warrants to El Paso that:

                  (a) Ramshorn is a corporation duly incorporated, validly
existing and in good standing under the laws of its jurisdiction of
incorporation, and has all corporate power and all material governmental
licenses, authorizations, permits, consents and approvals required to carry on
its business as now conducted.

                  (b) The execution, delivery and performance by Ramshorn of
this Agreement and the performance by Ramshorn of its obligations hereunder are
within its corporate powers and have been duly authorized by all necessary
corporate action on the part of Ramshorn. This Agreement constitutes a valid and
binding agreement of Ramshorn enforceable in accordance with its terms, except
as (i) the enforceability hereby may be limited by bankruptcy, insolvency,
moratorium or similar laws affecting the enforcement of creditors' rights
generally and (ii) the availability of equitable remedies may be limited by
equitable principles of general applicability.

                  (c) The execution, delivery and performance by Ramshorn of its
obligations hereunder do not and will not (i) contravene or conflict with the
certificate of incorporation or bylaws of Ramshorn, (ii) contravene or conflict
with or constitute or default (without regard to any requirement of notice or
the lapse of time or both) any provision of any law, regulation, judgment,
injunction, order or decree binding upon or applicable to Ramshorn, or any
indenture, mortgage, lien, lease, agreement or instrument to which Ramshorn is a
party or by which it or any of its assets or properties is bound.

                                   ARTICLE III
                                    PAYMENTS

          3.1 Payments by Ramshorn. Ramshorn shall pay each Investment Invoice
by wire transfer to El Paso's account on or before fifth (5th) Business Day of
the month following the month in which Ramshorn receives such Investment
Invoice.



                                       15
<PAGE>


          3.2 Payments by El Paso.

                  (a) The Net Overriding Royalty Interest for the Subject Wells
shall be calculated collectively using the Cash Method of Accounting. For each
month, the Net Overriding Royalty Interest for the Subject Wells shall be paid
to Ramshorn on the seventh (7th) Business Day of the month following such month.
For example, the Net Overriding Royalty Interest for the month of January (which
normally includes revenues for the sale of Oil and Gas produced in November)
will be paid on or before the seventh (7th) Business Day of February. Each such
payment made shall reduce the Payout Account balance pro tanto.

                  (b) The After Payout Overriding Royalty Interest shall be
calculated in the same manner and paid at the same time that El Paso pays the
lessors under the Subject Leases.

                  (c) Pending payment over of the Net Profits accruing to the
Net Overriding Royalty Interest and, if applicable, the proceeds accruing to the
After Payout Overriding Royalty Interest, the same shall be held by El Paso for
the benefit of Ramshorn.

          3.3 Interest on Past Due Payments. Any undisputed amount not paid by
El Paso or Ramshorn when due shall bear, and the owing party will pay, interest
at the Agreed Rate or the maximum contract rate permitted by the applicable
usury laws in the state in which the Subject Wells are located, whichever is
less, plus attorney's fees, court costs, and other costs in connection with the
collection of unpaid amounts.

          3.4 Net Profits Account.

                  (a) A single account (the "Net Profits Account") shall be
maintained by El Paso for the Subject Wells. The Net Profits Account shall be
credited with the aggregate Gross Proceeds received by El Paso, and shall be
charged with the aggregate Production Costs (or as the case may be, Excess
Production Costs) with respect to the Subject Wells, in each case using the Cash
Method of Accounting.

                  (b) On or before the date of payment as set forth in Section
3.2 hereof, El Paso shall furnish to Ramshorn a detailed statement clearly
reflecting the credits and debits to on a per well basis, and the balance of,
the Net Profits Account and the Payout Account as of the close of business on
the last Business Day of the preceding calendar month. Any Excess Production
Costs reflected by any such statement shall be carried forward to the next and
succeeding month or months until the Excess Production Costs shall have been
liquidated. In the event that Net Profits exist in the Net Profits Account at
the end of any month, payment to Ramshorn of the amount of Net Profits pursuant
to Section 3.2 shall be accomplished by wire transfer to Ramshorn's account,
pursuant to instructions given by Ramshorn to El Paso. Following any such
payment, the balances of the Net Profits Account and the Payout Account shall be
reduced by the amount of such payment.

                                   ARTICLE IV
                             POOLING AND UNITIZATION

          4.1 Pooling. Prior to the Payout Date, El Paso shall have the right
and power to pool and unitize any of the Subject Leases and to alter, change or
amend or terminate any pooling or



                                       16
<PAGE>


unitization agreements heretofore or hereafter entered into, as to all or any
part of the land covered hereby, and as to Oil, Gas or both, upon such terms and
provisions as El Paso shall, in conformance with prudent industry practices and
the relevant Subject Leases, determine. If and whenever through the exercise of
such right and power, or pursuant to any law now in effect or hereafter enacted
or any rule, regulation or order of any governmental body or official, any of
the Subject Leases are pooled or unitized in any manner, the Net Overriding
Royalty Interest insofar as it affects such Subject Leases shall also be pooled
and unitized and in any such event such Net Overriding Royalty Interest in such
Subject Leases shall apply to and affect only the production from the relevant
Subject Well (and not any other wells within such unit except as set forth in
Section 4.2) which accrues to such Subject Leases under and by virtue of the
pooling and unitization. In such event, Ramshorn's Investment Percentage shall
not change; however, Ramshorn's Net Profits from the Subject Wells may increase
or decrease due to an increase or decrease in El Paso's net revenue interest in
the unitized Subject Well.

          4.2 Adjustment to Net Overriding Royalty Interest. If such pooling or
unitization occurs before the Payout Date and after El Paso had invoiced
Ramshorn for the pooled or unitized Subject Well, then any amounts paid or
received by El Paso for a capital cost adjustment as a result of such pooling or
unitization shall be included as an increase or decrease, respectively, in the
Investment Costs of such well and reflected in a Well Cost Adjustment. If there
are other wells in such pooled acreage or unit in which El Paso acquires an
interest as the result of such pooling or unitization and such capital cost
adjustment, then El Paso shall assign a Net Overriding Royalty Interest in such
wells to Ramshorn. Ramshorn shall not have any interest in any subsequent well
drilled in such pooled acreage or unit unless such well is a Subject Well.

                                    ARTICLE V
                                   ASSIGNMENTS

          5.1 Restriction on Ramshorn's Assignment. The sale of the Net
Overriding Royalty Interest has not been registered under the Securities Act of
1933, as amended (the "Act") and the Net Overriding Royalty Interest may not be
sold or transferred in the absence of an effective registration statement under
the Act or the availability of an exemption from registration thereunder,
including the exemption for any transfers to "qualified institutional buyers" as
defined in and in accordance with Rule 144A as promulgated under the Act.
Ramshorn may transfer or assign any portion of its rights and obligations
hereunder, the Net Overriding Royalty Interest and/or the After Payout
Overriding Royalty Interest to any Affiliate of Ramshorn. Prior to the
expiration of the Project Term, Ramshorn may transfer or assign any portion of
its rights and obligations hereunder and the Net Overriding Royalty Interest to
any such "qualified institutional buyer"; provided, however, such assignment or
transfer must be approved by El Paso, which approval shall not unreasonably be
withheld. After the expiration of the Project Term, Ramshorn may transfer any of
the Net Overriding Royalty Interest or the After Payout Overriding Royalty
Interest and its rights hereunder without restriction, subject to compliance
with any applicable securities laws or regulations; provided, however, if the
Net Overriding Royalty Interest or the After Payout Overriding Royalty Interest
is divided among and owned by four (4) or more co-owners, El Paso, at its
discretion, may require such co-owners to appoint Ramshorn as agent, with full
authority to enter into and execute division orders or other agreements for
disposition of the co-owners' respective shares of Oil and Gas produced from the



                                       17
<PAGE>


Subject Wells, and to receive payment of the proceeds from the sale thereof; and
provided further, however, in the case of assignments or transfers after the
expiration of the Project Term but before the Payout Date, each assignee or
transferee must acknowledge in writing that it and the Net Overriding Royalty
Interest are subject to this Agreement.

          5.2 Assignments by El Paso. If El Paso assigns its interest in a
Subject Well before the Payout Date, then it shall notify the assignee of the
existence of this Agreement and secure a written acknowledgement that the
Subject Well being assigned is specifically subject to the rights of Ramshorn as
set forth herein. El Paso will then provide Ramshorn with a copy thereof.

          5.3 Purchase by El Paso.

                  (a) If El Paso intends to sell its entire interest in a
Subject Well for cash to a non-Affiliate in a bona fide, arm's-length
transaction prior to the date at which the cumulative amount of proceeds paid or
payable by the buyer(s) for all Subject Well(s) theretofore sold or proposed to
be sold equals or exceeds $10,000,000, then El Paso shall have the option to
purchase Ramshorn's Net Overriding Royalty Interest and After Payout Overriding
Royalty Interest in the affected Subject Well by paying to Ramshorn an amount in
cash equal to the Present Value of its Net Overriding Royalty Interest and After
Payout Overriding Royalty Interest.

                  (b) If El Paso intends to sell its entire interest in a
Subject Well in a transaction described in Section 5.3(a) after the date
referred to therein, then El Paso shall have the option to purchase Ramshorn's
Net Overriding Royalty Interest and After Payout Overriding Royalty Interest in
the affected Subject Well by paying Ramshorn an amount in cash equal to (i) the
Investment Percentage multiplied by (ii) the net sale proceeds attributable to
such well.

                  (c) Upon payment by El Paso to Ramshorn of the applicable
purchase price as specified in Section 5.3(a) or (b), Ramshorn shall execute and
deliver to El Paso a Partial Reconveyance and Termination of Overriding Royalty
Interest covering such interest substantially in the form attached hereto as
Exhibit "F-1" (for recordation in Texas) or "F-2" (for recordation in
Louisiana). The amount of such payment shall be deducted from the Payout
Account. If a Subject Well(s) is to be sold in a transaction that includes other
El Paso properties, the portion of the proceeds allocable to the Subject Well(s)
shall be determined by reference to the buyer's purchase price allocation, made
in good faith, or if no such allocation exists, the allocation shall be
determined by El Paso in the exercise of its good faith judgment. At least ten
(10) Business Days prior to the consummation of any transaction covered by this
Section 5.3, El Paso will provide Ramshorn with a written notice thereof and
detail with respect to the purchase price allocation (if applicable) sufficient,
in Ramshorn's judgment, to enable it to address the reasonableness of the
allocation. If Ramshorn disputes the allocation and the parties cannot resolve
the matter themselves, the dispute will be referred to Netherland, Sewell &
Associates, Inc. for determination of an allocation for purposes of this Section
5.3, whose decision will be final.

                  (d) El Paso's purchase option provided for in this Section 5.3
shall terminate at the Payout Date.



                                       18
<PAGE>


                                   ARTICLE VI
                               RECORDS AND REPORTS

          6.1 Books and Records. El Paso shall at all times maintain true and
correct books and records sufficient to determine the amounts payable to
Ramshorn hereunder, including, but not limited to, a Net Profits Account to
which Gross Proceeds, Production Costs and Excess Production Costs are credited
and charged, and a Payout Account.

          6.2 Audits. Ramshorn, upon notice in writing to El Paso, shall have
the right to audit El Paso's accounts and records relating to the Net Profits
Accounts, Payout Account and After Payout Overriding Royalty Interest for any
calendar year within the twenty-four (24) month period following the end of such
calendar year; provided, however, the making of an audit shall not extend the
time for the taking of written exception to and the adjustments of accounts as
provided for in Section 6.4 of this Agreement. El Paso shall bear no portion of
Ramshorn's audit cost incurred under this Section 6.2 unless agreed to by El
Paso. The audits shall not be conducted more than once each year without prior
approval of El Paso. Unless prohibited under confidentiality agreements, El
Paso, upon written request, shall furnish Ramshorn with any and all accounting
information pertaining to the Subject Wells in El Paso's possession. Ramshorn
shall reimburse El Paso, at its option, for all reasonable costs incurred to
furnish such information.

          6.3 Statement and Reports. Until the Payout Date, on or before the
date of payment as specified in Section 3.2 hereof, El Paso shall deliver to
Ramshorn a statement showing the computation of Net Profits attributable to the
immediately preceding month and the computation of Net Profits paid to Ramshorn
from the date hereof until the end of such month. Such report shall be in form
satisfactory to Ramshorn, and shall include, among other things reasonably
requested by Ramshorn, historical and forecast production volumes for the
Subject Wells, summary reports of drilling and completion activities on drilling
or completed Subject Wells during such month, anticipated spud dates for other
Subject Wells as at the end of such month and such other information as Ramshorn
may reasonably require. After the Payout Date, El Paso shall deliver to
Ramshorn, with each cash payment of After Payout Overriding Royalty Interest
proceeds, a statement in such detail as is required by applicable laws or
regulations governing payments of oil and gas royalties, and with such
additional detail as Ramshorn may reasonably specify reflecting the computation
of such payment. Upon Ramshorn's request, El Paso will provide Ramshorn with
copies of any drilling or division order title opinions obtained by El Paso
covering any Subject Wells and reasonable access to El Paso's land files related
to such wells.

          6.4 Ramshorn's Exceptions to Statements. If Ramshorn takes exception
to any item or items included in the monthly statements rendered by El Paso to
the computations of the pricing or volumes of any Oil and Gas and such exception
is made within two (2) years after such monthly payment date, Ramshorn shall
notify El Paso in writing, setting forth in such notice the specific charges
complained of and to which exception is taken or the specific credits which
should have been made and allowed; and with respect to such complaints and
exceptions as are justified, adjustment shall be made. Any exception not made
within such two (2) year period shall be deemed waived and not subject to
further audit.



                                       19
<PAGE>


          6.5 Geological Data. Prior to the Payout Date, El Paso shall, subject
to their reasonable availability and the limitations of confidentiality
undertakings with co-owners or other third parties, at Ramshorn's cost and
expense furnish Ramshorn and its duly authorized agents and representatives,
including its advisers and consultants (herein collectively referred to as its
"Agents"), copies of all electric and other logs of the Subject Wells. Prior to
the Payout Date, Ramshorn and its Agents shall also have access to all records
regarding all cores, cuttings, and other geological, well and production data
secured from operations on the Subject Wells. Ramshorn shall not have access to
any seismic data in El Paso's possession. After the Payout Date, Ramshorn and
its representatives shall have access to all records regarding production data,
future capital investment plans, marketing arrangements, processing arrangements
and any other data necessary, as determined by Ramshorn in its reasonable
discretion, to evaluate Ramshorn's After Payout Overriding Royalty Interest. All
information furnished to Ramshorn pursuant to this Section 6.5 is confidential
and for the sole benefit of Ramshorn and shall not be shown or disclosed by
Ramshorn to any Person except as provided in the Confidentiality Agreement dated
April 23, 2003, by and between El Paso and Ramshorn Brothers, Inc.

          6.6 Reserve Reports. El Paso will furnish or cause to be furnished the
following reserve reports:

                  (a) Promptly after December 31 of each calendar year
(commencing with the calendar year 2003), and in any event not later than March
31 of the next succeeding calendar year, a reserve report covering the Subject
Wells in the form prepared by the Approved Independent Engineer for El Paso for
its oil and gas properties, as of December 31 of such calendar year;

                  (b) Promptly after March 31, June 30 and September 30 of each
calendar year (commencing with the calendar year 2004), and in any event not
later than May 15, August 15 and November 15, respectively, of such calendar
year, a reserve report covering the Subject Wells in the form prepared by El
Paso as of the end of such calendar quarter and, in the case of such reports
prepared after January 1, 2004, updating the current Reserve Report prepared by
the Approved Independent Engineer; and

                  (c) Each such report shall conform to the standards prescribed
by Rule 4-10 of Regulation S-X promulgated by the Securities and Exchange
Commission under the Act for financial accounting and reserve reporting purposes
applicable to registrants employing the full cost method of accounting.

          6.7 Reconciliation Report. At March 31, 2004, and if requested by
Ramshorn at September 30, 2004 and March 31, 2005, El Paso shall deliver to
Ramshorn a report reconciling on a per well basis all amounts reflected in
Investment Invoices submitted to Ramshorn prior to the date of such report (or
if applicable, since the date of the most recent such report) to actual
Investment Costs for each Subject Well covered by any such invoice. At
Ramshorn's request, the parties shall meet to review the report(s) and if the
applicable reconciliation reveals that estimated costs reflected in the
Investment Invoices covered by such reconciliation routinely and, in the
reasonable judgment of Ramshorn, materially exceeded the actual costs (it being
understood that the inclusion of a 10% contingency amount shall not be
considered for this purpose), the parties will negotiate in good faith with a
view toward adjusting El Paso's



                                       20
<PAGE>


invoicing practices. If the parties are unable to reach agreement, Ramshorn may
require that future Investment Invoices be submitted based upon the last
estimated costs of the drilling and completion of the Subject Wells furnished by
El Paso to Ramshorn prior to the execution of this Agreement.

                                   ARTICLE VII
                           OPERATION OF SUBJECT LEASES

          7.1 Prudent Operator Standard.

                  (a) El Paso will conduct and carry on or cause to be conducted
and carried on the exploration, development, maintenance and operation of the
Subject Wells with reasonable and prudent business judgment and in accordance
with sound oil and gas field practices. Without limitation of the foregoing,
prior to commencement of drilling operations on any Subject Well, El Paso will
obtain a drilling title opinion or, in the case of a drillsite which is held by
production, conduct such other title review and related due diligence as would
be consistent with sound oil and gas field practices for the location and nature
of such drillsite and related Subject Well.

                  (b) Nothing contained in this Agreement shall be deemed to
prevent or restrict El Paso from electing to participate or not to participate
in any operation which is to be conducted under the terms of any operating
agreement, unit operating agreement, contract for development or similar
instrument affecting or pertaining to the Subject Wells (or any operation
conduced on a Subject Well) or if El Paso elects not to participate (which
election shall be made without taking into consideration the Net Overriding
Royalty Interest) allowing consenting parties to conduct non-consent operations
thereon.

                  (c) Nothing contained in this Agreement shall be deemed to
prevent or restrict El Paso from drilling or participating in the drilling of
other oil and gas wells (which are not Subject Wells) on the Subject Leases and,
except as provided in Section 4.2, Ramshorn shall have no interest in such other
wells drilled on the Subject Leases or production therefrom.

                  (d) Any conveyance, assignment, or Encumbrance made by El Paso
or Ramshorn on the Subject Wells or Subject Leases insofar as the Subject Leases
cover the Subject Wells shall be made expressly subject to this Agreement and
Ramshorn's Net Overriding Royalty Interest or, if applicable, After Payout
Overriding Royalty Interest, and any Encumbrance made by El Paso (other than a
Permitted Third Party Net Profits Interest) or Ramshorn shall be made expressly
subordinate to the rights of the other party. Except for such expressly
subordinated conveyances, assignments and Encumbrances, and except for Permitted
Encumbrances, (i) prior to the recordation of an assignment to Ramshorn of the
Net Overriding Royalty Interest therein, El Paso at its own expense will keep
and maintain the Subject Wells and the Subject Leases insofar as the Subject
Leases cover and contribute to the Subject Wells free and clear of all
Encumbrances, except Permitted Encumbrances, arising by, through or under El
Paso or any Affiliate and (ii) after such recordation, El Paso at its own
expense will keep and maintain Ramshorn's Net Overriding Royalty Interest or, if
applicable, After Payout Overriding Royalty Interest free and clear of all
Encumbrances, except Permitted Encumbrances, arising by, through or under El
Paso or any Affiliate; provided, however, only for purposes of El Paso's



                                       21
<PAGE>


special warranty of title set forth in this sentence, Permitted Third Party Net
Profits Interests shall not be considered Permitted Encumbrances. Should an
adverse claim be made against, or a cloud develop upon the title to any part of
Ramshorn's Net Overriding Royalty Interest other than such as may arise by,
through or under El Paso or Ramshorn or a Permitted Encumbrance, unless
otherwise agreed by Ramshorn, El Paso will take all commercially reasonable
actions to defend such claim or to remove such cloud, the expenses of which
defense or removal shall be Production Costs hereunder.

                  (e) Oil and Gas from the Subject Wells shall be sold for
market value.

          7.2 Abandonment of Properties. Nothing herein contained shall obligate
El Paso to drill or complete any Subject Well, to continue to operate any
Subject Well, or to operate or maintain in force or attempt to maintain in force
any of the Subject Leases when, in El Paso's reasonable opinion, such well or
Subject Lease is not economical.

          7.3 Affiliated Transactions. El Paso may agree, contract or arrange
with itself or any of its Affiliates for the performance of services or the sale
or lease of equipment, and supplies used in connection with the Subject Leases,
and the payment of compensation therefor, as if such parties were independent
contractors; provided, however, that the terms of such agreement, contract or
arrangement are embodied in a written document setting forth the specific
arrangements; and provided further, however, that the compensation for such
services or sale or lease shall be (i) comparable to and competitive with that
of unrelated third parties rendering comparable services or selling or leasing
equipment or supplies in the same geographical area and (ii) paid only for
services, equipment or supplies reasonably necessary for the prudent operation
of, and actually furnished with respect to, such Subject Leases.

          7.4 Delay Rentals, Minimum Royalties, and Shut-in Gas Payments. El
Paso shall use its reasonable commercial efforts to pay or cause to be paid in a
proper and timely manner any delay rentals, minimum royalties, and shut-in gas
payments, if any, which may be necessary to maintain in force and effect the
Subject Leases, except any portion thereof which El Paso has determined to
abandon pursuant hereto. Notwithstanding anything to the contrary herein, El
Paso shall not be liable to Ramshorn for any failure to pay or the incorrect
payment of any delay rentals, minimum royalty, shut-in gas payments, or any
other contractual obligation, unless such failure shall be attributable to the
gross negligence or willful misconduct of El Paso.

          7.5 Accounting. El Paso shall account for revenues and costs
associated with the Subject Wells consistent with its normal business practices
for other wells in the region of the Subject Wells unless this Agreement
requires a different accounting.

                                  ARTICLE VIII
                              TERM AND TERMINATION

          8.1 Term. This Agreement shall terminate ninety (90) days after the
Payout Date; provided, however, any obligation to pay money under this Agreement
accruing to the Net Overriding Royalty Interest or After Payout Overriding
Royalty Interest or to convey or re-convey any interest in a Subject Lease or
Subject Well shall not terminate.



                                       22
<PAGE>


          8.2 Project Term. The "Project Term" shall refer to the period ending
on June 30, 2005.

          8.3 Early Termination of Project Term. Either party may notify the
other party in writing and terminate the Project Term effective thirty (30) days
after such notice is received by the other party. The shortened Project Term is
referred to hereinafter as the "Revised Project Term". This Agreement shall
continue to cover all Subject Wells that had been commenced prior to the
expiration of the Revised Project Term. In the event Ramshorn requests the early
termination of the Project Term, any Subject Wells that had not yet been
commenced on or before the expiration of the Revised Project Term shall be
automatically deleted from Exhibit "A" to this Agreement and shall no longer be
considered "Subject Wells." In the event El Paso requests the early termination
of the Project Term or if all of the Subject Wells have not been commenced by
the end of the original Project Term, then, in such event (i) Ramshorn shall,
until the Payout Date, receive its Net Overriding Royalty Interest in all of the
Subject Wells regardless of when such wells are commenced, even if following the
end of the Revised Project Term or original Project Term, as applicable, (ii)
the Investment Percentage shall be adjusted effective as of the first day of
each calendar quarter to be equal to the total purchase price paid by Ramshorn
under Section 2.2 divided by total Investment Costs of the Subject Wells which
are commenced prior to the Payout Date, and (iii) Ramshorn shall not be required
to pay any amounts under Section 2.2 or otherwise related to the Subject Wells
commenced after the end of the Revised Project Term or original Project Term, as
applicable. Whenever the Investment Percentage is adjusted, El Paso and Ramshorn
shall execute an Amendment to Assignment of Overriding Royalty Interest
substantially in the form attached hereto as Exhibit "G-1" (for recordation in
Texas) and "G-2" (for recordation in Louisiana).

          8.4 Deemed Early Termination by Ramshorn. In the event of any
unexcused failure, inability or refusal by Ramshorn to pay any undisputed
portion of an Investment Invoice within fifty-nine (59) days from the due date
of such invoice, then Ramshorn shall be deemed to have elected to terminate the
Project Term effective as of the first day of the month immediately preceding
the month in which such invoice was due; provided, however, if such payment
default occurs with respect to an Investment Invoice rendered at a time when any
prior payment default remains uncured, the period within which such default may
be cured with respect to such invoice shall be twenty-nine (29) days, in lieu of
the fifty-nine (59)-day period otherwise provided for above.

                                   ARTICLE IX
                                  MISCELLANEOUS

          9.1 Further Assurances. Should any additional instruments of
assignment and conveyance be required to describe more specifically any
interests subject hereto, El Paso and Ramshorn agree to execute and deliver the
same. Also, if any other or additional instruments are required in connection
with the transfer of any State or Federal lease interests in order to comply
with applicable laws or regulations, El Paso and Ramshorn will execute and
deliver the same. Without limitation of the foregoing, where Exhibit "A"
indicates that a Subject Well is a "drill to earn" prospect or proposed to be
located on lands covered by leases not yet assigned, or words to similar effect,
promptly upon assignment to El Paso of the affected leasehold interest(s), El
Paso will prepare and the parties will execute an amendment to the Memorandum of
Purchase and



                                       23
<PAGE>


Sale Agreement, or Declaration and Agreement, as appropriate, to be filed in the
appropriate county or parish; provided, however, such amendments need be filed
no more often than once a month (but in any event, as to any particular Subject
Lease assigned to or acquired by El Paso after the date hereof, prior to the
submission to Ramshorn of an Investment Invoice related to the Subject Well
proposed to be drilled thereon); and provided further, however, if El Paso is
not entitled to receive an assignment until completion of a Subject Well because
such well is drilled under a farmout or similar "drill to earn" agreement, the
parenthetical in the foregoing proviso shall not be applicable.

          9.2 Notices. Except as otherwise expressly provided in this Agreement,
all notices, demands, requests or other communications required or permitted to
be given pursuant to this Agreement shall be in writing and may be given either
(i) in person, (ii) by United States mail, certified or registered, return
receipt requested, postage prepaid, (iii) by nationally recognized overnight
courier or (iv) by prepaid telegram, telex, cable, telecopy or similar means
(with signed confirming copy to follow by mail), as follows:

                  IF TO EL PASO:

                  Nine Greenway Plaza
                  Houston, Texas  77046
                  Attention:  J. T. Elzner
                  Telephone:  832.676.7817
                  Fax:  832.676.1353

                  IF TO RAMSHORN:

                  Ramshorn Investments, Inc.
                  515 W. Greens Road, Suite 1000
                  Houston, Texas 77067-4525
                  Attention:  Jordan "Digger" Smith
                  Telephone:  281-874-0035
                  Fax:  281-874-8414

                  WITH A COPY TO:

                  Law Dept of Nabors Corporate Services, Inc.
                  515 W. Greens Road, Suite 1200
                  Houston, Texas 77067-4525
                  Attention:  Laura Doerre
                  Phone number is 281-874-0035
                  Fax:  281-775-8431

          9.3 Binding Effect. This Agreement shall bind and inure to the benefit
of successors in interest and assigns of El Paso and Ramshorn.

          9.4 GOVERNING LAW. THE VALIDITY, EFFECT AND CONSTRUCTION OF THIS
AGREEMENT SHALL BE GOVERNED BY THE LAWS OF THE STATE OF TEXAS



                                       24
<PAGE>


WITHOUT GIVING EFFECT TO ITS CONFLICTS OF LAWS PROVISIONS, EXCEPT WHERE THE LAWS
OF ANOTHER JURISDICTION ARE MANDATORILY APPLICABLE WITH RESPECT TO THE
CONVEYANCE OF THE NET OVERRIDING ROYALTY INTEREST.

          9.5 Headings. Article and Section headings used in this Agreement are
for convenience only and shall not affect the construction of this Agreement.

          9.6 Intention of the Parties.

                  (a) Nothing herein contained is intended to create, nor shall
the same be construed as creating (under state law or for tax purposes), any
mining partnership, commercial partnership or other partnership relation or
joint venture. If, however, the parties hereto are deemed to constitute a
partnership for federal or state income tax purposes, the parties elect to be
excluded from the application of Subchapter K, Chapter 1, Subtitle A of the Code
(or any similar state law) and agree not to take any position inconsistent with
such election.

                  (b) In addition, the parties hereto intend that the Net
Overriding Royalty Interest conveyed hereby by El Paso to Ramshorn shall at all
times be treated as a non-operating "economic interest" in the Oil and Gas
within the meaning of the Code (or any corresponding provisions of succeeding
law) and a non-operating mineral right for state law purposes. It is further
intended that the Assignment(s) of Overriding Royalty Interest contemplated
hereunder constitutes a present, absolute and indefeasible conveyance of a real
property interest (fee simple determinable) in Texas and other common law
jurisdictions and of an immovable property right in Louisiana. Nothing herein
shall suggest, nor shall anything herein be construed to suggest, that the
purchase and sale transactions contemplated herein constitute one or more
financing transactions. However, for the avoidance of doubt, Ramshorn shall be
entitled to file a copy of the Memorandum of Purchase and Sale Agreement as a
precautionary UCC non-standard financing statement to better evidence and
perfect its interest in the Net Profits, Net Overriding Royalty Interest, the
After Payout Overriding Royalty Interest, the Oil and Gas attributable thereto
and the proceeds thereof.

          9.7 Counterpart Execution. This Agreement may be executed in multiple
counterparts, each of which shall be deemed an original agreement for all
purposes hereunder.

          9.8 Validity and Severability. If any provision of this Agreement is
held to be illegal, invalid or unenforceable under the present or future laws
effective during the term of this Agreement, such provision shall be fully
severable; this Agreement shall be construed and enforced as if such illegal,
invalid or unenforceable provision had never comprised a part of this Agreement;
and the remaining provisions of this Agreement shall remain in full force and
effect and shall not be affected by the illegal, invalid or unenforceable
provision or by its severance from this Agreement. In lieu of such illegal,
invalid or unenforceable provisions, there shall be added automatically as a
part of this Agreement a provision as similar in terms to such illegal, invalid
or unenforceable provision as may be possible and be legal, valid and
enforceable.


                                       25
<PAGE>


          9.9 Negotiated Instrument. This Agreement represents a negotiated
agreement and no portion shall be construed for or against either party by
virtue of its having been drafted by that party.

          9.10 Securities Act. Ramshorn (i) understands that the Net Overriding
Royalty Interest has not been, and will not be, registered under the Act, or
under any state securities laws, and is being offered and sold in reliance upon
certain federal and state exemptions, (ii) is acquiring the Net Overriding
Royalty Interest solely for Ramshorn's own account for investment purposes, and
not with a view to the public distribution thereof, (iii) is a sophisticated
investor with knowledge and experience in business and financial matters, (iv)
has received certain information concerning the Net Overriding Royalty Interest
and has had the opportunity to obtain additional information as desired to
evaluate the merits and the risks inherent in purchasing the Net Overriding
Royalty Interest, (v) is able to bear the economic risk and lack of liquidity
inherent in holding the Net Overriding Royalty Interest, and (vi) is an
"accredited investor" as defined in Regulation D promulgated under the Act.

          9.11 Amendments. Any amendment hereto shall become effective only upon
the express written consent of El Paso and Ramshorn, at which time it shall
become effective as to all parties hereto. No amendment, modification or
alteration of the terms hereof shall be binding unless the same is in writing
and is in accordance with this Section 9.11.

          9.12 Confidentiality. Notwithstanding anything herein to the contrary,
the parties (and each employee, representative or other agent of El Paso or
Ramshorn) may disclose to any and all Persons, without limitation of any kind,
the U.S. federal income tax treatment and tax structure of the transaction
contemplated herein and all materials of any kind (including opinions and other
tax analyses) that are provided to the parties relating to such tax treatment
and tax structure. For this purpose, "tax structure" is limited to facts
relevant to the U.S. federal income tax treatment of such transaction and does
not include information relating to the identity of the parties, their
respective Affiliates, agents or advisors.

          9.13 Benefits of Agreement Restricted to Parties. Nothing in this
Agreement expressed or implied is intended or shall be construed to give to any
Person other than El Paso and Ramshorn, and their respective successors and
assigns, any legal or equitable right, remedy or claim under or in respect of
this Agreement or any covenant, condition or provision therein or herein
contained; and all such covenants, conditions and provisions are and shall be
held to be for the sole and exclusive benefit of El Paso and Ramshorn, and their
respective successors and assigns.

          9.14 Exhibits.

                  (a) The forms of instruments attached hereto as Exhibit "D-1"
through "G-2" are prepared for use in connection with Subject Wells drilled by
El Paso.

                  (b) In order to satisfy the requirements of the Louisiana
public records doctrine and other related Louisiana laws, the parties have
contemporaneously executed a Declaration and Agreement in the form attached
hereto as Exhibit "H", which shall be recorded in each parish in Louisiana where
any lands covered by Subject Leases are located. As among



                                       26
<PAGE>


the parties hereto, such Declaration and Agreement shall be deemed a part of,
and subsumed within and under, this Agreement, it being the parties' express
understanding and intention that as among the parties, such Declaration and
Agreement shall not create, and shall not be construed to create, any additional
rights or obligations beyond those provided for or created herein or hereunder
nor shall such Declaration and Agreement limit, expand, alter or in any other
way affect any such rights or obligations; and the parties acknowledge and agree
that as among themselves, this Agreement alone shall govern the transactions
contemplated herein.

          9.15 Liability of Ramshorn. In no event shall Ramshorn be personally
liable or responsible in any way for payment of any part of the costs, expenses
or liabilities incurred in connection with the exploring, developing, operating
and maintaining of the Subject Leases or the Subject Wells, and El Paso agrees
to indemnify and hold Ramshorn harmless from and against all such costs,
expenses or liabilities; provided, however, all costs and expenses described in
this Section 9.15 shall, to the extent the same relate to the period prior to
the Payout Date, nevertheless be charged against the Net Profits Account to the
extent herein permitted.

Executed the date first written above.

                                         EL PASO PRODUCTION OIL & GAS USA, L.P.
                                         By  El Paso Production Oil & Gas
                                             Company, its general partner

                                         By: /s/ John T. Elzner
                                             -----------------------------------
                                             John T. Elzner, Senior Vice
                                             President


                                         RAMSHORN INVESTMENTS, INC.

                                         By: /s/ Jordan "Digger" Smith
                                             -----------------------------------
                                             Jordan "Digger" Smith, President



                                       27


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.25
<SEQUENCE>5
<FILENAME>h13476exv10w25.txt
<DESCRIPTION>EXPLORATION PARTICIPATION AGREEMENT
<TEXT>
<PAGE>
                                                                   EXHIBIT 10.25

                            EXPLORATION PARTICIPATION
                                    AGREEMENT

                                 By and Between

                      El Paso Production Oil & Gas Company

                     El Paso Production Oil & Gas USA, L.P.


                                       And


                           Ramshorn Investments, Inc.



                                    PROSPECTS

                                    Andromeda
                                     Cabeza
                                    Liverpool
                                    Mesquite
                                East San Salvador
                                  Mad Island UT
                                  Pebble Beach
                              N. Sako (Los Indios)
                              S. Sako (Los Indios)

<PAGE>

                            EXPLORATION PARTICIPATION
                                    AGREEMENT

This Exploration Participation Agreement is dated as of November 6, 2003, and is
by and between El Paso Production Oil & Gas Company, El Paso Production Oil &
Gas USA, L.P. (collectively "EL PASO") and Ramshorn Investments, Inc.
("PARTICIPANT"), hereinafter referred to singularly as "Party" and jointly as
"Parties."

                                    RECITALS

WHEREAS, El Paso represents, but does not warrant, that it is the owner of a
working interest in various oil and gas leases and lease options located within
the Prospects as are more fully described in Exhibits A-1 through A-9; and

WHEREAS, Participant has expressed a desire to earn an interest in the Prospects
and participate in the joint exploration and development of the Prospects as
described in Exhibits A-1 through A-9 and establish areas of mutual interest.

NOW, THEREFORE, in consideration of the premises and of the mutual promises
exchanged and contained within this Agreement, the receipt and sufficiency of
which are hereby acknowledged, the Parties hereby agree as follows:

                                    SECTION 1
                                    EXHIBITS

All references in this Agreement to Exhibits without further qualification shall
mean the Exhibits listed below and attached to this Agreement. Each of the
Exhibits listed below are made part of this Agreement and shall be deemed
incorporated into this Agreement by this reference as if the full text of each
Exhibit were contained within the body of this Agreement. If any provision of
any Exhibit is inconsistent with any provision contained in the body of this
Agreement, then the provisions in the body of this Agreement shall prevail.

<Table>
<S>                   <C>                         <C>
    Exhibit A-1   -   Andromeda                   Plat and lease schedule
    Exhibit A-2   -   Cabeza                      Plat and lease schedule
    Exhibit A-3   -   Liverpool                   Plat and lease schedule
    Exhibit A-4   -   Mesquite                    Plat and lease schedule
    Exhibit A-5   -   E. San Salvador             Plat and lease schedule
    Exhibit A-6   -   Mad Island UT               Plat and lease schedule
    Exhibit A-7   -   Pebble Beach                Plat and lease schedule
    Exhibit A-8   -   N. Sako (Los Indios)        Plat and lease schedule
    Exhibit A-9   -   S. Sako (Los Indios)        Plat and lease schedule
    Exhibit B     -   Commitment Well List
    Exhibit C     -   Joint Operating Agreement
    Exhibit D     -   Form of Assignment
</Table>

<PAGE>

<Table>
<S>                   <C>
    Exhibit E-1   -   East Quinn
    Exhibit E-2   -   Kimber (Los Indios)
</Table>

                                    SECTION 2
                                   DEFINITIONS

As used in this Agreement, the following terms have the meanings here ascribed
to them.

2.1 "AFE" means the authority for expenditure which sets forth the estimated
cost of drilling and completing an oil and gas well.

2.2 "Affiliate" means, with respect to any Person, any other Person directly or
indirectly controlling, controlled by, or under common control with, such
Person. For purposes of this definition, the term "control" (including the terms
"controlled by" and "under common control with") means the possession, directly
or indirectly, of the power to direct or cause the direction of the management
and policies of any Person, whether through the ownership of voting securities
or by contract or otherwise. "Person" means an individual, partnership (whether
general or limited), limited liability company, corporation, trust, estate,
unincorporated association, nominee, joint venture or other entity.

2.3 "Agreement" means this Exploration Participation Agreement, together with
its attached Exhibits.

2.4 "Area of mutual interest" or "AMI" means the land within the heavy dark line
marked on the relevant plat, being one of the plats attached hereto as Exhibits
A-1 through A-9. There are nine (9) AMI's covered by this Agreement..

2.5 To "commence" a well means to have a drilling rig on location and to
commence turning the drill bit to the right.

2.6 "Commitment Wells" means the wells described on Exhibit "B". Each of these
wells will be considered an "Initial Well" as that term is described in article
VI A of the Operating Agreement.

2.7 "Effective Date" means September 1, 2003.

2.8 "El Paso" is defined on page 1.

2.9 "El Paso's Original Share" means El Paso's cost bearing interest in a
Commitment Well based upon El Paso's interest in the Leases covering such
Commitment Well prior to the assignment to Participant described in subsection
3.3.

2.10 "Estimated Completion Cost" means the good faith estimate of costs to run
the production string of casing and install related equipment reasonable
necessary for the well to be

<PAGE>

capable of producing oil and gas to the tanks or pipelines (including the
construction of tanks or pipeline connections), as set forth in the AFE for such
Commitment Well.

2.11 "Estimated Drilling Cost" means the good faith estimate of costs to drill
and log a Commitment Well to the total objective depth, as set forth in the AFE
for a Commitment Well.

2.12 "Estimated P&A Cost" means El Paso's good faith estimate of the plugging
and abandonment costs for a Commitment Well.

2.13 "Leases" means oil and gas leases, mineral interests, royalty interests,
net profits interests, options or agreements to acquire or earn the foregoing
such as farmins, farmouts, participation agreements and similar agreements.

2.14 "Oil and Gas" (whether capitalized or not) means the oil, gas, casinghead
gas, gas condensate, and all other liquid or gaseous hydrocarbons and other
marketable substances produced therewith and all other liquid or gaseous
hydrocarbons.

2.15 "Operating Agreement" means the applicable operating agreements covering a
Prospect, the form of which is attached hereto as Exhibit B.

2.16 "Participant" is defined on page 1.

2.17 "Party" and "Parties" are defined on page 1.

2.18 "Prospect" means the land within the heavy dark line marked on the relevant
plat, being one of the plats attached hereto as Exhibits A-1 through A-9. There
are nine (9) Prospects covered by this Agreement.

2.19 "Through the tanks" means all operations necessary to drill and complete a
well and install related equipment reasonably necessary for the well to be
capable of producing oil and gas to tanks or pipelines, including but not
limited to any well control operations, sidetracking, deepening and
environmental remediation.

                                    SECTION 3
                        PARTICIPATION IN COMMITMENT WELLS

3.1 COMMITMENT WELLS: Participant agrees to participate in the Commitment Wells
proposed by El Paso on or before September 1, 2004 and which are commenced on or
before December 31, 2004. Participant shall not have the option to elect not to
participate in the drilling and completion "through the tanks" of a Commitment
Well even if the relevant Operating Agreement or the AFE has a provision that
purports to allow Participant to elect not to participate. Participant shall not
have the right to make any other elections set forth in the relevant Operating
Agreement regarding such Commitment Well until such Commitment Well has been
drilled and completed "through the tanks" or abandoned as a dry hole. These
restrictions apply only to the Commitment Wells.

<PAGE>

Participant assumes the liability for and shall pay El Paso for TWENTY-FIVE
percent (25%) of El Paso's Original Share of the cost of drilling and completing
each Commitment Well "through the tanks," and plugging and abandoning any
Commitment Well that is a dry hole, including but not limited to the cost of
sidetracking, deepening, well control, environmental remediation and any
unanticipated costs. If El Paso receives either a direct refund of any of these
costs from a third party or insurance proceeds that includes Participants share
of such costs, then Participant will benefit to the same percentage that they
paid for such costs.

El Paso shall have the sole right to determine the final design, location, and
depth of each Commitment Well. El Paso shall propose a Commitment Well by
submitting an AFE for such well to Participant.

3.2 PAYMENT. Within five (5) days of the receipt of the AFE for a Commitment
Well, Participant will pay by wire transfer an amount equal to TWENTY-FIVE
percent (25%) of El Paso's Original Share of the Estimated Drilling Cost. Within
five (5) days of the receipt of notice that El Paso will attempt to complete a
Commitment Well, Participant will pay by wire transfer an amount equal to
TWENTY-FIVE percent (25%) of El Paso's Original Share of the Estimated
Completion Cost. Within five (5) days of the receipt of a notice from El Paso
that a Commitment Well will be plugged and abandoned as a dry hole, Participant
will pay by wire transfer an amount equal to TWENTY-FIVE percent (25%) of the
Estimated P&A Cost as set forth in such notice. If a Commitment Well is
completed "through the tanks", then all subsequent costs will be paid in
accordance with the relevant Operating Agreement.

If the actual cost of drilling and completing a Commitment Well "through the
tanks," and plugging and abandoning the Commitment Well if it is a dry hole, is
not equal to the sum of the Estimated Drilling Cost, Estimated Completion Cost
and Estimated P&A Cost paid by Participant with respect to that well, then El
Paso will invoice Participant for TWENTY-FIVE percent (25%) of El Paso's
Original Share of the amount by which actual costs exceed such Estimated Costs
or refund to Participant TWENTY-FIVE percent (25%) of El Paso's Original Share
of the amount by which such Estimated Costs exceed actual costs. Such invoice or
refund shall occur within 15 days after the date on which the amount of such
invoice or refund can be calculated.

3.3 INTERESTS EARNED AND ASSIGNMENT. By participating in a Commitment Well,
timely paying Estimated Drilling Cost for such Commitment Well, and timely
executing and delivering the Operating Agreement for the relevant Prospect to El
Paso, Participant shall earn an undivided TWELVE-AND-ONE-HALF percent (12.5%) of
El Paso's Original Share in the Leases in the Prospect in which such Commitment
Well is located. Within 5 days after receipt of payment of the Estimated
Drilling Cost for such Commitment Well, and the execution and delivery by
Participant of the Operating Agreement for the Prospect in which such Commitment
Well is located, El Paso will execute and record an assignment conveying an
undivided TWELVE-AND-ONE-HALF percent (12.5%) of El Paso's Original Share in and
to the Leases described on the relevant Prospect Exhibit attached hereto plus
any additional Leases that may be acquired by El Paso within such Prospect prior
to the date of such assignment. Any Leases that have expired before the date of
such assignment shall be excluded from the assignment.

<PAGE>

The assignment will be on the form of the assignment attached hereto as Exhibit
"D". El Paso shall assign its interest free of any retained override, production
payment or net profits payable to or any burden created by El Paso or any
Affiliate of El Paso. The Assignment will be made WITHOUT WARRANTY OF TITLE
EITHER EXPRESS OR IMPLIED EXCEPT THAT EL PASO WILL WARRANT TITLE AGAINST ALL
CLAIMS BY, THROUGH OR UNDER EL PASO.

3.4 OPERATING AGREEMENTS. Except as otherwise provided herein, operations on
each Prospect will be conducted pursuant to, and the relationship of the Parties
with respect to each Prospect shall be governed by, the terms and provisions of
the Operating Agreement for each Prospect, a model of which is attached as
Exhibit "C." Participant shall pay its proportionate share of the costs of
operations on the Prospect, other than as provided in Sections 3.1 and 3.2
above, based upon Participant's ownership interest in the relevant Leases. Each
Operating Agreement shall designate El Paso or an El Paso affiliate as operator.
Should El Paso enter into an operating agreement with a third party on all or
part of a Prospect prior to the execution of the Operating Agreement for such
Prospect, then the Operating Agreement covering such Prospect shall be made
subject to such prior operating agreement.

3.5 INFORMATION. In connection with the drilling of the Commitment Wells,
Participant shall have free and unrestricted access, including the opportunity
to occupy available space on transportation utilized by Participant for travel
to and from the Commitment Wells, to the derrick floor, at Participant's sole
cost, risk and expense, to observe drilling, logging, coring, testing, and other
operations, to inspect core samples, to verify drilling depths and conditions,
and to review results of all tests, electrical logging surveys and other
downhole evaluation surveys.

                                    SECTION 4
                               LEASE ACQUISITIONS

4.1 NO LEASE ACQUISITIONS BY PARTICIPANT. Participant will not acquire any
interest in any Lease within a Prospect (except from El Paso pursuant to this
Agreement) or contact any party owning rights within a Prospect for any reason
prior to the date of the assignment from El Paso to Participant for the relevant
Prospect and the execution of an Operating Agreement for such Prospect. If
Participant obtains an interest in a Lease within a Prospect in violation of the
preceding sentence, then Participant shall, within 30 days of securing such
interest, disclose to El Paso the terms conditions and costs associated with
such interest. El Paso shall then have 15 days to elect to acquire ONE HUNDRED
percent (100%) of such interest at no cost. El Paso's obligation to assign
interests in Leases to Participant pursuant to Section 3.3 above shall include
the Leases acquired by El Paso from Participant pursuant to this Section.

                                    SECTION 5
                  FAILURE TO PROPOSE OR DRILL COMMITMENT WELLS

<PAGE>

5.1 PROPOSAL BY PARTICIPANT. If El Paso fails to propose the drilling of any
Commitment Well on or before September 1, 2004 then Participant shall have the
right to propose any such Commitment Well during the period from September 2,
2004 until October 1, 2004 by delivering to El Paso during such time period an
AFE for such Commitment Well and an executed Operating Agreement for the
Prospect in which the Commitment Well is located. If Participant proposes the
drilling of such Commitment Well during this time period, then El Paso shall
have the right to elect to participate or not participate in such well as
provided in the Operating Agreement. If El Paso elects to participate in the
well, then Participant shall pay its share of costs of the well as provided in
section 3.1 and 3.2 above and earn the interests as provided in section 3.3
above. If El Paso elects not to participate in such Commitment Well, then
Participant shall be liable for and shall pay for ONE HUNDRED percent (100%) of
the cost of drilling such Commitment Well that is attributable to El Paso's
Original Share of such Commitment Well. Upon payment of such costs of the well
in the manner and time frame set forth in article 3.2 above (i) Participant
shall earn an undivided TWELVE-AND-ONE-HALF percent (12.5%) of El Paso's
Original Share in the Leases in the Prospect in which such Commitment Well is
located as provided in Section 3.3 above, (ii) Participant shall be entitled to
receive the non-consent penalty provided for in the Operating Agreement as to
SEVENTY FIVE percent (75%) of El Paso's Original Share in the Commitment Well,
and (iii) El Paso remaining TWELVE-AND-ONE-HALF percent (12.5%) of El Paso's
Original Share in such Commitment Well shall not be subject to the non-consent
penalty in the Operating Agreement and El Paso shall not be obligated to pay any
costs of such Commitment Well "through the tanks."

5.2 NO DRILLING. El Paso shall use reasonable efforts to commence all timely
proposed Commitment Wells on or before December 31, 2004; provided however, El
Paso shall not be liable to Participant for any damages or liabilities for El
Paso's failure to timely commence a Commitment Well for any reason or no reason
at all. If a timely proposed Commitment Well is not commenced on or before
December 31, 2004, then the term of this Agreement INSOFAR AND ONLY INSOFAR as
it relates to the Prospect in which such Commitment Well is located shall
automatically be extended to June 1, 2005. If Participant had made a payment of
the Estimated Drilling Costs for a Commitment Well which was not commenced on or
before December 31, 2004, then El Paso shall either (i) deliver to Participant
notice that El Paso will commence the drilling of such Commitment Well on or
before February 1, 2005, or (ii) notify Participant that El Paso shall refund
such Estimated Drilling Costs to Participant upon the reassignment of the Leases
in the Prospect for such Commitment Well that had been conveyed to Participant
by El Paso. If El Paso does not commence such Commitment Well on or before
February 1, 2005, then, pending the actual commencement of such Commitment Well,
El Paso shall refund such Estimated Drilling Costs to Participant upon the
reassignment of the Leases in the Prospect for such Commitment Well that had
been conveyed to Participant by El Paso.

If a timely proposed Commitment Well is not commenced on or before June 1, 2005,
then El Paso will so notify Participant and (i) El Paso shall refund to
Participant any Estimated Drilling Costs paid by Participant on such Commitment
Well which had not been previously refunded (ii) Participant shall reassign the
Leases in the Prospect for such Commitment Well that had been conveyed to
Participant by El Paso, and (iii) the Prospect in which such Commitment Well is
located will be no longer subject to this Agreement and Participant shall have
no further

<PAGE>

rights to earn any interest in such Prospect. If an Operating Agreement covering
such Prospect had been executed by the Parties, then such Operating Agreement
shall automatically terminate and be null and void.

5.3 NO PROPOSAL. If El Paso fails to propose the drilling of any Commitment Well
on or before September 1, 2004 and Participant does not timely propose the
drilling of such Commitment Well, then El Paso will so notify Participant and
the Prospect will be no longer subject to this Agreement and Participant shall
have no further rights to earn any interests in such Prospect.

                                    SECTION 6
                                   DISCLAIMERS

6.1 INFORMATION ABOUT THE COMMITMENT WELLS. El Paso disclaims all liability and
responsibility for any representation, warranty (other than the representations
and warranties specifically set forth in this Agreement), statements or
communications (orally or in writing) to Participant, including any information
contained in any opinion, information or advice that may have been provided to
Participant by any employee, officer, director, agent, consultant, engineer or
engineering firm, trustee, representative, partner, member, beneficiary,
stockholder or contractor of El Paso wherever and however made, including those
made in any meeting, presentation, data room or internet site and any
supplements or amendments thereto or during any negotiations with respect to
this Agreement or any confidentiality agreement previously executed by El Paso
and Participant with respect to the Commitment Wells. EL PASO MAKES NO WARRANTY
OR REPRESENTATION, EXPRESS, STATUTORY OR IMPLIED, AS TO (i) THE ACCURACY,
COMPLETENESS OR MATERIALITY OF ANY DATA, INFORMATION OR RECORDS FURNISHED TO
PARTICIPANT IN CONNECTION WITH THE COMMITMENT WELLS, INCLUDING WITHOUT
LIMITATION SEISMIC DATA AND EL PASO'S INTERPRETATION AND OTHER ANALYSIS THEREOF;
(ii) THE PRESENCE, QUALITY AND QUANTITY OF HYDROCARBON RESERVES (IF ANY)
ATTRIBUTABLE TO THE COMMITMENT WELLS; (iii) THE ABILITY OF THE COMMITMENT WELLS
TO PRODUCE HYDROCARBONS, INCLUDING WITHOUT LIMITATION PRODUCTION RATES, DECLINE
RATES AND RECOMPLETION OPPORTUNITIES; (iv) THE PRESENT OR FUTURE VALUE OF THE
ANTICIPATED INCOME, COSTS OR PROFITS, IF ANY, TO BE DERIVED FROM THE COMMITMENT
WELLS; AND (v) ANY PROJECTIONS AS TO EVENTS THAT COULD OR COULD NOT OCCUR. ANY
DATA, INFORMATION OR OTHER RECORDS FURNISHED BY EL PASO ARE PROVIDED TO
PARTICIPANT AS A CONVENIENCE AND PARTICIPANT'S RELIANCE ON OR USE OF THE SAME IS
AT PARTICIPANT'S SOLE RISK.

6.2 INDEPENDENT INVESTIGATION. Participant has made its own independent
investigation, analysis and evaluation of the transactions contemplated by this
Agreement (including Participant's own estimate and appraisal of the extent and
value of the Oil and Gas reserves attributable to the Commitment Wells and the
costs to explore for and develop the reserves if found). Participant has had, or
will have prior to Closing and Participant has had or will have

<PAGE>

prior to acceptance of this Agreement, access to all information necessary to
perform its investigation and has not relied on any representations by El Paso
(other than the representations specifically set forth in this Agreement). El
Paso has provided Participant and its experts the opportunity to review El
Paso's data on the Commitment Wells and Participant has reviewed such data that
it deems necessary. Participant understands and acknowledges that El Paso is not
guaranteeing the actual costs of other vendors supplying services to the
Commitment Wells.

6.3 NO WARRANTY OF TITLE. El Paso makes no representation or warranty of title
except El Paso warrants title against all claims by, through or under El Paso,
to any interests in the Leases within the Prospects and shall not be responsible
or liable to Participant if El Paso's title to such interest does not exist or
fails for any reason, including but not limited to failure to pay rentals,
minimum royalties or other lease maintenance payments or perform any condition
of a lease, or if El Paso is unable to acquire such interest.

6.4 DELAY RENTALS. During the term of this Agreement and prior to the effective
date of any Operating Agreement covering a Prospect executed by the Parties, El
Paso shall pay or tender (or cause to be paid or tendered) all rentals, minimum
royalties and other lease maintenance payments, if any, which may hereafter
become due under the terms of the said leases covered by this Agreement in such
Prospect, but shall have no liability to Participant for failure to make any
such payment or tender or to make same timely or properly, unless such failure
is due to the gross negligence or willful misconduct of El Paso. Prior to such
effective date, El Paso will be responsible for all rental costs on the Leases
within such Prospect without reimbursement from Participant. After such
effective date, all rentals on the Leases within such Prospect will be paid and
reimbursed in accordance with the terms of the respective Operating Agreements.

                                    SECTION 7
                                 TAX PARTNERSHIP

7.1 TAX PARTNERSHIP. Attached to each Operating Agreement will be a Tax
Partnership as Exhibit "G". It is the intent and the Party will take such steps
as necessary to operate these Prospects as separate Tax Partnerships, pursuant
to the Tax Partnership Agreements described herein.

                                    SECTION 8
                                   USE OF RIGS

8.1 SERVICES OF AFFILIATES OF RAMSHORN. If Participant and its affiliates
satisfy, in El Paso's reasonable opinion, El Paso's standards and requirements
as set forth below, then until October 31, 2006, El Paso will employ Participant
or its affiliates under the terms of that certain Master Drilling Contract
between Sonat Exploration Company and Nabors Drilling USA, Inc. dated August 19,
1997, as amended from time to time, or that certain IADC Drilling Contract
between Coastal Oil & Gas Corporation and Nabors Drilling USA, Inc. dated
September 15, 1997, as amended from time to time, to drill the wells covered by
this Agreement or the

<PAGE>

Operating Agreements. This Section 8.1 shall survive the termination of this
Agreement until October 31, 2006, after which time the parties will negotiate in
good faith the continued use of rigs for wells covered by this Agreement or the
Operating Agreements; provided however, neither El Paso not Participant shall be
under any obligation to the other to enter into any agreement regarding the use
of such rigs after October 31, 2006.

To be employed in the drilling of a well (to be determined on a well by well
basis), Participant must be able to supply a quality drilling rig capable of
efficiently drilling to the proposed depth manned by competent and efficient
crews. The rig must be capable of being rigged up and ready to commence drilling
on or before El Paso's estimated spud date. If El Paso and Participant have not
agreed to drilling rates, then Participant's rates for a well must also be at
competitive rates for the type of rig, the proposed depth and the efficiency of
the rig and crew in drilling such well.

Notwithstanding anything to the contrary above, El Paso shall retain the right
to drill any well using any of the two rigs it currently has committed or under
contract with Grey Wolf.

                                    SECTION 9
                                   ASSIGNMENT

9.1 ASSIGNMENT. This Agreement may not be assigned by Participant other than to
an Affiliate. Subject to subsection 9.2 below, Participant may assign its rights
in and to any interest in a Lease that has been assigned to it by El Paso
pursuant to Section 3.3.

9.2 PREFERENTIAL RIGHT TO PURCHASE. If Participant desires to transfer, sell,
farm out, assign, or otherwise dispose of all or part of its interest in a Lease
that has been assigned to it by El Paso pursuant to Section 3.3. Participant
shall promptly give written notice to El Paso with full information about the
proposed transaction, including, but not limited to, the name and address of the
prospective transferee (who must be ready, willing, and able to acquire the
interest and deliver the stated consideration therefor), the consideration and
all terms related to the transfer. In the case of a package sale of oil and gas
interests that includes all or part of Participant's interest in such Leases, or
if the proposed transaction is structured as a non-simultaneous, like-kind
exchange under Section 1031 of the Internal Revenue Code of 1986, as amended
("Code"), the interest that is subject to this preferential right shall be
separately valued and the notice shall state the value attributed to the
interest by the prospective transferee. El Paso shall have an optional prior
right, for a period of thirty (30) days after receipt of the notice, to elect to
purchase or acquire on the same terms and conditions, or on equivalent terms for
a non-cash transaction, all of such interests that the Participant is proposing
to transfer. This preferential right shall apply separately to each Lease or
part thereof covered by this Agreement, regardless of whether it is included in
the proposed transaction along with other oil and gas interests, whether as a
sale, farm out, or non-simultaneous, like-kind exchange, and no provision in
this Agreement shall be interpreted to defeat this preferential right. Upon
exercise of this preferential right, El Paso shall agree to perform all
obligations of the prospective transferee under the proposed transaction only
for such interest subject to the proposed transaction. This preferential right,
however, shall not exist or apply when Participant proposes (a) to mortgage

<PAGE>

its interest; (b) to dispose of or transfer its interest to an Affiliate by (i)
merger, (ii) reorganization, or (iii) consolidation; (c) to sell all, or
substantially all, of its exploration and production properties located in the
United States of America; or (d) to transfer the interest under a property
exchange transaction other than a non-simultaneous, like-kind exchange under
Section 1031 of the Code. If the proposed transaction is not consummated within
six (6) months after receipt of the notice by El Paso, the interest shall again
be governed by this subsection and the preferential right shall again arise for
the offered interest as herein described.

                                   SECTION 10
                       PARTICIPANT'S FAVORED NATION STATUS

10.1 FAVORED NATIONS. Subject to the exceptions listed below, if El Paso has
entered, or enters into a transaction prior to the completion of the Commitment
Well or the plugging and abandonment of the Commitment Well within a Prospect,
in which El Paso conveys or has conveyed any interest or any part of its
interest in any wells, leases or lands in any part of such Prospect on terms
more favorable to a third party than the terms of this Agreement pertaining to
(i) the promote (i.e. 25% for 12.5% through the tanks), (ii) the proportionate
costs borne on any well or (iii) the proportion of net revenue interest earned
to costs borne on any well, lease or prospect (a "Better Agreement"), then El
Paso will provide the details of such transaction to Participant. Participant
will have 15 days from the date of the receipt of such details by Participant to
elect in writing to remove such Prospect from this Agreement and enter into a
new agreement with El Paso (a "New Agreement") substantially the same as such
Better Agreement INSOFAR AND ONLY INSOFAR as the Better Agreement covers such
Prospect, with all appropriate recalculations and adjustments to be promptly
made by El Paso and Participant and all further necessary actions to be taken
promptly by El Paso and Participant to put them in the same position as if this
Agreement did not cover such Prospect ab initio and such New Agreement had been
executed contemporaneously with this Agreement. Participant's failure to respond
in writing within such 15 day period will be deemed an election not to convert
to the New Agreement on such Prospect.

Notwithstanding the foregoing paragraph, Participant shall not have the right to
elect to convert to the New Agreement on such Prospect under the following
situations:

         (i) The Better Agreement contains more favorable terms as a result of a
         reciprocal trade involving said third party's prospects, leasehold or
         wells, independent of the location of the same either within such
         Prospect or outside such Prospect, or

         (ii) The Better Agreement contains more favorable terms as a result of
         a merger, reorganization, consolidation or sale of all or substantially
         all of El Paso's assets to a subsidiary or parent company or to a
         subsidiary of a parent company, or to a company in which El Paso owns a
         majority of the stock.

10.2 TERM OF FAVORED NATIONS. The provisions of Section 10.1 shall terminate as
to each Prospect upon the completion of the Commitment Well or the plugging and
abandonment of the Commitment Well within such Prospect.

<PAGE>

10.3 RIGHT OF FIRST REFUSAL ON EAST QUINN AND KIMBER. If El Paso elects to drill
a well on the East Quinn and Kimber (Los Indios) prospects, as outlined on plats
attached as Exhibits E-1 and E-2 within two years from the date of this
Agreement, then Participant shall have the option, but not the obligation to
enter into an exploration participation agreement substantially in the form of
this Agreement covering such prospect. Participant shall have five (5) business
days after receipt of notice of El Paso's decision to drill such well to elect
in writing to enter into such an exploration participation agreement. A failure
to make an election shall be deemed to be an election not to enter into such
exploration participation agreement. An election not to enter into such
exploration participation agreement on one prospect is not a waiver of the right
to enter into such exploration participation agreement on the other prospect.

10.4 PRESENTATIONS ON FUTURE PROSPECTS. If El Paso presents a promoted prospect
to a party that is not an affiliate of El Paso prior to November 1, 2005, then
El Paso shall offer to make the same presentation on such promoted prospect to
Participant. Participant shall have five (5) business days after receipt of
notice of such presentation to elect in writing to attend a presentation of a
promoted prospect at El Paso's offices. Participant shall execute a
confidentiality agreement covering such promoted prospect before the
presentation to Participant. A failure to make an election shall be deemed to be
an election not to attend the presentation. An election not to attend a
presentation on one promoted prospect is not a waiver of the right to attend
future presentations of promoted prospects.

Neither El Paso nor Participant shall be under any obligation to the other to
enter into any agreement on such promoted prospect.

A "promoted prospect" means one or more leases grouped together by El Paso as
potentially containing hydrocarbons in commercial quantities in one or more
geological formations in which a participant may earn an undivided interest in
such leases by paying a greater proportion of the drilling costs and other costs
than the costs attributable to the undivided interest in the leases which may be
earned by the participant.

                                   SECTION 11
                                    INSURANCE

11.1 INSURANCE. As to all operations hereunder prior to the completion of the
Commitment Well or the plugging and abandonment of the Commitment Well within a
Prospect, El Paso shall carry for the benefit and protection of the parties
hereto, the following:

         a)       Worker's Compensation as required by the laws of the state in
                  which the operations are conducted and Employer's Liability
                  insurance with minimum limits of $1,000,000 each
                  accident/disease per employee. Worker's Compensation and
                  Employer's Liability insurance to include coverage for all
                  claims under the United State Longshoremen's and Harbor
                  Worker's Act, the Jones Act, OCSLA, "in rem", and alternate
                  employer/borrowed servant.

<PAGE>

         b)       Comprehensive General Liability insurance in the amount of
                  $5,000,000, including coverage for Premises/Operations,
                  Independent Contractors, Personal Injury, Products/Completed
                  Operations, Blanket Contractual Liability, Explosion/Collapse,
                  Sudden and Accidental Pollution and "in rem".

         c)       Umbrella (excess of underlying insurance coverage mentioned
                  above) with a combined limit per occurrence coverage of not
                  less than $10,000,000.

To the extent permitted by law, every such insurance policy shall contain a
waiver on the part of the insurance carrier of all rights, by subrogation or
otherwise, against Participant. To the extent permitted by law, Participant
shall also be named as additional insured in each such policy.

11.2 EXCLUSION. The above insurance shall cover Participant only in its capacity
as an oil and gas lessee, as a co-owner in an oil and gas well, and as a
non-operator and shall not cover Participant as a drilling contractor or other
supplier of materials or services on an oil and gas well or related activities.

                                   SECTION 12
                                 CONFIDENTIALITY

12.1 CONTRACT AND OPERATIONS STRICTLY CONFIDENTIAL. Any information disclosed to
Participant by El Paso regarding the Prospects shall be deemed to be covered by
that certain confidentiality agreement dated April 23, 2003 by and between El
Paso and Participant. That Agreement is hereby ratified and confirmed by the
Parties.

                                   SECTION 13
                                  MISCELLANEOUS

13.1 TERM. This Agreement shall terminate on March 1, 2005 except for any
liabilities and obligations accruing on or prior to such date, which shall
survive the termination of this Agreement.

13.2 VALIDITY AND SEVERABILITY. If any provision of this Agreement is held to be
illegal, invalid or unenforceable under the present or future laws effective
during the term of this Agreement, such provision shall be fully severable; this
Agreement shall be construed and enforced as if such illegal, invalid or
unenforceable provision had never comprised a part of this Agreement; and the
remaining provisions of this Agreement shall remain in full force and effect and
shall not be affected by the illegal, invalid or unenforceable provision or by
its severance from this Agreement. In lieu of such illegal, invalid or
unenforceable provisions, there shall be added automatically as a part of this
Agreement a provision as similar in terms to such illegal, invalid or
unenforceable provision as may be possible and be legal, valid and enforceable.

13.3 NEGOTIATED INSTRUMENT. This Agreement represents a negotiated agreement and
no portion shall be construed for or against either Party by virtue of its
having been drafted by that Party.

<PAGE>

13.4 SECURITIES ACT. Participant (a) understands that the oil and gas leases
have not been, and will not be, registered under the Securities Act of 1933 (the
"Securities Act"), or under any, state securities laws, and are being offered
and sold in reliance upon certain federal and state exemptions, (b) is acquiring
an interest in the oil and gas leases solely for Participant's own account for
investment purposes, and not with a view to the distribution thereof, (c) is a
sophisticated investor with knowledge and experience in business and financial
matters, (d) has received certain information concerning the oil and gas leases
and has had the opportunity to obtain additional information as desired to
evaluate the merits and the risks inherent in holding an interest in the oil and
gas leases, (e) is able to bear the economic risk and lack of liquidity inherent
in holding an interest in the oil and gas leases, and (f) is an accredited
investor as defined in Regulation D promulgated under the Securities Act.

13.5 WAIVER OF DECEPTIVE TRADE PRACTICES ACTS. PARTICIPANT WAIVES ITS RIGHTS
UNDER THE DECEPTIVE TRADE PRACTICES ACT SECTION 17.41 et seq., TEXAS BUSINESS &
COMMERCE CODE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS, AND UNDER SIMILAR
STATUTES ADOPTED IN OTHER STATES, TO THE EXTENT THEY HAVE APPLICABILITY TO THE
TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. AFTER CONSULTATION WITH AN ATTORNEY
OF ITS SELECTION, PARTICIPANT CONSENTS TO THIS WAIVER.

13.6 GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN
ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS. NOT INCLUDING, HOWEVER, ANY OF
ITS CONFLICTS OF LAW RULES WHICH WOULD DIRECT OR REFER TO THE LAWS OF ANOTHER
JURISDICTION.

13.7 AMENDMENTS. Any amendment hereto shall become effective only upon the
express written consent of El Paso and Participant, at which time it shall
become effective as to all Party hereto. No amendment, modification or
alteration of the terms hereof shall be binding unless the same is in writing
and is in accordance with this subsection.

13.8 NOTICES. Except as otherwise expressly provided in this Agreement, all
notices, payments, demands, requests or other communications required or
permitted to be given pursuant to this Agreement shall be in writing and may be
given either (i) in person, (ii) by United States mail, certified or registered,
return receipt requested, postage prepaid, (iii) by prepaid telegram, telex,
cable, telecopy, or similar means (with signed confirming copy to follow by
mail), or (iv) by any other method permitted by law, as follows:

           IF TO EL PASO:                     IF TO PARTICIPANT

           Nine Greenway Plaza                515 W. Greens Road, Suite 1000
           Houston, Texas  77046              Houston, Texas 77067
           Attention:  J. T. Elzner           Attention: J.R. "Digger" Smith
           Telephone:  832.676.7817           Telephone: 281 775 8527
           Fax:  832.676.1353                 Fax: 281 775 8414

<PAGE>

                                              With copy to:

                                              Law Department
                                              515 W. Greens Road, Suite 1000
                                              Houston, Texas 77067
                                              Attention: Bruce M. Taten
                                              Telephone: 281 775 8556
                                              Fax: 281 775 8431

14.9 ENTIRE AGREEMENT. This Agreement, its Exhibits, and other documents
executed in accordance with this Agreement constitute the entire agreement of
the parties with respect to the subject matter hereof.

Executed as of the date first written above.

                                        El Paso Production Oil & Gas Company


                                        By: /s/ Jon R. Nelsen
                                            ------------------------------------
                                            Jon R. Nelsen, Attorney in Fact


                                        El Paso Production Oil & Gas USA, L.P.
                                        By El Paso Production Oil & Gas Company
                                                 its General Partner

                                        By: /s/ Jon R. Nelsen
                                            ------------------------------------
                                            Jon R. Nelsen, Attorney in Fact


                                        Ramshorn Investments, Inc.


                                        By: /s/ Jordan R. Smith
                                            ------------------------------------
                                        Name: Jordan R. Smith
                                              ----------------------------------
                                        Title: President
                                               ---------------------------------


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.26
<SEQUENCE>6
<FILENAME>h13476exv10w26.txt
<DESCRIPTION>EXPLORATION PARTICIPATION AGREEMENT
<TEXT>
<PAGE>
                                                                   EXHIBIT 10.26


                            EXPLORATION PARTICIPATION
                                    AGREEMENT

                                 By and Between

                           El Paso Production Company


                                       And


                           Ramshorn Investments, Inc.



                               CATAPULT PROSPECTS

                                 Florence Canal
                                 Blackfish Lake
                                 Little Lake S.

<PAGE>

                            EXPLORATION PARTICIPATION
                                    AGREEMENT

This Exploration Participation Agreement is dated as of November 6, 2003, and is
by and between El Paso Production Company ("EL PASO") and Ramshorn Investments,
Inc. ("PARTICIPANT"), hereinafter referred to singularly as "Party" and jointly
as "Parties."


                                    RECITALS

WHEREAS, El Paso represents, but does not warrant, that it is the owner of a
working interest in various oil and gas leases and lease options located within
the Prospects as are more fully described in Exhibits A-1 through A-3; and

WHEREAS, Participant has expressed a desire to earn an interest in the Prospects
and participate in the joint exploration and development of the Prospects as
described in Exhibits A-1 through A-3 and establish areas of mutual interest.

NOW, THEREFORE, in consideration of the premises and of the mutual promises
exchanged and contained within this Agreement, the receipt and sufficiency of
which are hereby acknowledged, the Parties hereby agree as follows:

                                    SECTION 1
                                    EXHIBITS

All references in this Agreement to Exhibits without further qualification shall
mean the Exhibits listed below and attached to this Agreement. Each of the
Exhibits listed below are made part of this Agreement and shall be deemed
incorporated into this Agreement by this reference as if the full text of each
Exhibit were contained within the body of this Agreement. If any provision of
any Exhibit is inconsistent with any provision contained in the body of this
Agreement, then the provisions in the body of this Agreement shall prevail.

<Table>
<S>                   <C>
   Exhibit A-1    -   Florence Canal            Plat and lease schedule
   Exhibit A-2    -   Blackfish Lake            Plat and lease schedule
   Exhibit A-3    -   Little Lake S.            Plat and lease schedule
   Exhibit B      -   Commitment Well List
   Exhibit C      -   Joint Operating Agreement
   Exhibit D      -   Form of Assignment
   Exhibit E      -   Overriding Royalty Interests and other Burdens
</Table>

                                    SECTION 2
                                   DEFINITIONS

As used in this Agreement, the following terms have the meanings here ascribed
to them.

<PAGE>

2.1 "AFE" means the authority for expenditure which sets forth the estimated
cost of drilling and completing an oil and gas well.

2.2 "Affiliate" means, with respect to any Person, any other Person directly or
indirectly controlling, controlled by, or under common control with, such
Person. For purposes of this definition, the term "control" (including the terms
"controlled by" and "under common control with") means the possession, directly
or indirectly, of the power to direct or cause the direction of the management
and policies of any Person, whether through the ownership of voting securities
or by contract or otherwise. "Person" means an individual, partnership (whether
general or limited), limited liability company, corporation, trust, estate,
unincorporated association, nominee, joint venture or other entity.

2.3 "Agreement" means this Exploration Participation Agreement, together with
its attached Exhibits.

2.4 "Area of mutual interest" or "AMI" means the land within the heavy blue line
marked on the relevant plat, being one of the plats attached hereto as Exhibits
A-1 through A-3. There are three (3) AMI's covered by this Agreement.

2.5 "Casing Point" means the point in time when a Commitment Well has reached
its authorized depth, and all tests have been completed, and the results thereof
furnished to Participant, and El Paso has given notice to Participant that El
Paso desires attempt to set casing and complete such Commitment Well.

2.6 To "commence" a well means to have a drilling rig on location and to
commence turning the drill bit to the right.

2.7 "Commitment Wells" means the wells described on Exhibit "B". Each of these
wells will be considered an "Initial Well" as that term is described in article
VI A of the Operating Agreement.

2.8 "Effective Date" means September 1, 2003.

2.9 "El Paso" is defined on page 1.

2.10 "El Paso's Original Share" means El Paso's cost bearing interest in a
Commitment Well based upon El Paso's interest in the Leases covering such
Commitment Well prior to the assignment to Participant described in subsection
3.3.

2.11 "Estimated Drilling Cost" means the good faith estimate of costs to drill
and log a Commitment Well to the total objective depth, as set forth in the AFE
for a Commitment Well.

2.12 "Estimated P&A Cost" means El Paso's good faith estimate of the plugging
and abandonment costs for a Commitment Well.


                                       2
<PAGE>

2.13 "Leases" means oil and gas leases, mineral interests, royalty interests,
net profits interests, options or agreements to acquire or earn the foregoing
such as farmins, farmouts, participation agreements and similar agreements.

2.14 "Oil and Gas" (whether capitalized or not) means the oil, gas, casinghead
gas, gas condensate, and all other liquid or gaseous hydrocarbons and other
marketable substances produced therewith and all other liquid or gaseous
hydrocarbons.

2.15 "Operating Agreement" means the applicable operating agreements covering a
Prospect, the form of which is attached hereto as Exhibit B.

2.16 "Participant" is defined on page 1.

2.17 "Party" and "Parties" are defined on page 1.

2.18 "Prospect" means the land within the heavy blue line marked on the relevant
plat, being one of the plats attached hereto as Exhibits A-1 through A-3. There
are three (3) Prospects covered by this Agreement.

                                    SECTION 3
                        PARTICIPATION IN COMMITMENT WELLS

3.1 COMMITMENT WELLS: Participant agrees to participate in the Commitment Wells
proposed by El Paso on or before September 1, 2004 and which are commenced on or
before December 31, 2004. Participant shall not have the option to elect not to
participate in the drilling of a Commitment Well even if the relevant Operating
Agreement or the AFE has a provision that purports to allow Participant to elect
not to participate. Participant shall not have the right to make any other
elections set forth in the relevant Operating Agreement regarding such
Commitment Well until such Commitment Well has been drilled to the Casing Point.
At Casing Point, Participant may elect to participate in the completion of such
Commitment Well as provided in the relevant Operating Agreement. These
restrictions apply only to the Commitment Wells.

Participant assumes the liability for and shall pay El Paso for TWENTY-FIVE
percent (25%) of El Paso's Original Share of the cost of drilling each
Commitment Well to the Casing Point and plugging and abandoning any Commitment
Well that is a dry hole, including but not limited to the cost of sidetracking,
deepening, well control, environmental remediation and any unanticipated costs.
If El Paso receives either a direct refund of any of these costs from a third
party or insurance proceeds that includes Participants share of such costs, then
Participant will benefit to the same percentage that they paid for such costs.

El Paso shall have the sole right to determine the final design, location, and
depth of each Commitment Well. El Paso shall propose a Commitment Well by
submitting an AFE for such well to Participant.

                                       3
<PAGE>

3.2 PAYMENT. Within five (5) days of the receipt of the AFE for a Commitment
Well, Participant will pay by wire transfer an amount equal to TWENTY-FIVE
percent (25%) of El Paso's Original Share of the Estimated Drilling Cost. Within
five (5) days of the receipt of a notice from El Paso that a Commitment Well
will be plugged and abandoned as a dry hole, Participant will pay by wire
transfer an amount equal to TWENTY-FIVE percent (25%) of the Estimated P&A Cost
as set forth in such notice. If a Commitment Well is drilled to the Casing
Point, then all subsequent costs to set casing and attempt to complete the well
or to conduct other operations will be paid in accordance with the relevant
Operating Agreement. If Participant elects not to participate in the completion
attempt, then it will be subject to the non-consent provisions of the relevant
Operating Agreement.

If the actual cost of drilling a Commitment Well to the Casing Point and
plugging and abandoning the Commitment Well if it is a dry hole, is not equal to
the sum of the Estimated Drilling Cost and Estimated P&A Cost paid by
Participant with respect to that well, then El Paso will invoice Participant for
TWENTY-FIVE percent (25%) of El Paso's Original Share of the amount by which
actual costs exceed such Estimated Costs or refund to Participant TWENTY-FIVE
percent (25%) of El Paso's Original Share of the amount by which such Estimated
Costs exceed actual costs. Such invoice or refund shall occur within 15 days
after the date on which the amount of such invoice or refund can be calculated.

3.3 INTERESTS EARNED AND ASSIGNMENT. By participating in a Commitment Well,
timely paying Estimated Drilling Cost for such Commitment Well, and timely
executing and delivering the Operating Agreement for the relevant Prospect to El
Paso, Participant shall earn an undivided TWELVE-AND-ONE-HALF percent (12.5%) of
El Paso's Original Share in the Leases in the Prospect in which such Commitment
Well is located. Within 5 days after receipt of payment of the Estimated
Drilling Cost for such Commitment Well, and the execution and delivery by
Participant of the Operating Agreement for the Prospect in which such Commitment
Well is located, El Paso will execute and record an assignment conveying an
undivided TWELVE-AND-ONE-HALF percent (12.5%) of El Paso's Original Share in and
to the Leases described on the relevant Prospect Exhibit attached hereto plus
any additional Leases that may be acquired by El Paso within such Prospect prior
to the date of such assignment. Any Leases that have expired before the date of
such assignment shall be excluded from the assignment. The assignment will be on
the form of the assignment attached hereto as Exhibit "D". El Paso shall assign
its interest free of any retained override, production payment or net profits
payable to or any burden created by El Paso or any Affiliate of El Paso. The
Assignment will be made WITHOUT WARRANTY OF TITLE EITHER EXPRESS OR IMPLIED
EXCEPT THAT EL PASO WILL WARRANT TITLE AGAINST ALL CLAIMS BY, THROUGH OR UNDER
EL PASO subject to the overriding royalty interests and other burdens described
on Exhibit "E" which El Paso has previously assigned or is obligated to assign.

3.4 OPERATING AGREEMENTS. Except as otherwise provided herein, operations on
each Prospect will be conducted pursuant to, and the relationship of the Parties
with respect to each Prospect shall be governed by, the terms and provisions of
the Operating Agreement for each Prospect, a model of which is attached as
Exhibit "C." Participant shall pay its proportionate share of the costs of
operations on the Prospect, other than as provided in Sections 3.1 and 3.2
above, based upon Participant's ownership interest in the relevant Leases. Each
Operating


                                       4
<PAGE>

Agreement shall designate El Paso or an El Paso affiliate as operator. Should El
Paso enter into an operating agreement with a third party on all or part of a
Prospect prior to the execution of the Operating Agreement for such Prospect,
then the Operating Agreement covering such Prospect shall be made subject to
such prior operating agreement.

3.5 INFORMATION. In connection with the drilling of the Commitment Wells,
Participant shall have free and unrestricted access, including the opportunity
to occupy available space on transportation utilized by Participant for travel
to and from the Commitment Wells, to the derrick floor, at Participant's sole
cost, risk and expense, to observe drilling, logging, coring, testing, and other
operations, to inspect core samples, to verify drilling depths and conditions,
and to review results of all tests, electrical logging surveys and other
downhole evaluation surveys.


                                    SECTION 4
                               LEASE ACQUISITIONS

4.1 NO LEASE ACQUISITIONS BY PARTICIPANT. Participant will not acquire any
interest in any Lease within a Prospect (except from El Paso pursuant to this
Agreement) or contact any party owning rights within a Prospect for any reason
prior to the date of the assignment from El Paso to Participant for the relevant
Prospect and the execution of an Operating Agreement for such Prospect. If
Participant obtains an interest in a Lease within a Prospect in violation of the
preceding sentence, then Participant shall, within 30 days of securing such
interest, disclose to El Paso the terms conditions and costs associated with
such interest. El Paso shall then have 15 days to elect to acquire ONE HUNDRED
percent (100%) of such interest at no cost. El Paso's obligation to assign
interests in Leases to Participant pursuant to Section 3.3 above shall include
the Leases acquired by El Paso from Participant pursuant to this Section.


                                    SECTION 5
                  FAILURE TO PROPOSE OR DRILL COMMITMENT WELLS

5.1 PROPOSAL BY PARTICIPANT. If El Paso fails to propose the drilling of any
Commitment Well on or before September 1, 2004 then Participant shall have the
right to propose any such Commitment Well during the period from September 2,
2004 until October 1, 2004 by delivering to El Paso during such time period an
AFE for such Commitment Well and an executed Operating Agreement for the
Prospect in which the Commitment Well is located. If Participant proposes the
drilling of such Commitment Well during this time period, then El Paso shall
have the right elect to participate or not participate in such well as provided
in the Operating Agreement. If El Paso elects to participate in the well, then
Participant shall pay its share of costs of the well as provided in section 3.1
and 3.2 above and earn the interests as provided in section 3.3 above. If El
Paso elects not to participate in such Commitment Well, then Participant shall
be liable for and shall pay for ONE HUNDRED percent (100%) of the cost of
drilling such Commitment Well that is attributable to El Paso's Original Share
of such Commitment Well. Upon payment of such costs of the well in the manner
and time frame set forth in article 3.2 above (i) Participant shall earn an
undivided TWELVE-AND-ONE-HALF


                                       5
<PAGE>
percent (12.5%) of El Paso's Original Share in the Leases in the Prospect in
which such Commitment Well is located as provided in Section 3.3 above, (ii)
Participant shall be entitled to receive the non-consent penalty provided for in
the Operating Agreement as to SEVENTY FIVE percent (75%) of El Paso's Original
Share in the Commitment Well, and (iii) El Paso's remaining TWELVE-AND-ONE-HALF
percent (12.5%) of El Paso's Original Share in such Commitment Well shall not be
subject to the non-consent penalty in the Operating Agreement and El Paso shall
not be obligated to pay any costs of such Commitment Well to the Casing Point.

5.2 NO DRILLING. El Paso shall use reasonable efforts to commence all timely
proposed Commitment Wells on or before December 31, 2004; provided however, El
Paso shall not be liable to Participant for any damages or liabilities for El
Paso's failure to timely commence a Commitment Well for any reason or no reason
at all. If a timely proposed Commitment Well is not commenced on or before
December 31, 2004, then the term of this Agreement INSOFAR AND ONLY INSOFAR as
it relates to the Prospect in which such Commitment Well is located shall
automatically be extended to June 1, 2005. If Participant had made a payment of
the Estimated Drilling Costs for a Commitment Well which was not commenced on or
before December 31, 2004, then El Paso shall either (i) deliver to Participant
notice that El Paso will commence the drilling of such Commitment Well on or
before February 1, 2005, or (ii) notify Participant that El Paso shall refund
such Estimated Drilling Costs to Participant upon the reassignment of the Leases
in the Prospect for such Commitment Well that had been conveyed to Participant
by El Paso. If El Paso does not commence such Commitment Well on or before
February 1, 2005, then, pending the actual commencement of such Commitment Well,
El Paso shall refund such Estimated Drilling Costs to Participant upon the
reassignment of the Leases in the Prospect for such Commitment Well that had
been conveyed to Participant by El Paso.

If a timely proposed Commitment Well is not commenced on or before June 1, 2005,
then El Paso will so notify Participant and (i) El Paso shall refund to
Participant any Estimated Drilling Costs paid by Participant on such Commitment
Well which had not been previously refunded (ii) Participant shall reassign the
Leases in the Prospect for such Commitment Well that had been conveyed to
Participant by El Paso, and (iii) the Prospect in which such Commitment Well is
located will be no longer subject to this Agreement and Participant shall have
no further rights to earn any interest in such Prospect. If an Operating
Agreement covering such Prospect had been executed by the Parties, then such
Operating Agreement shall automatically terminate and be null and void.

5.3 NO PROPOSAL. If El Paso fails to propose the drilling of any Commitment Well
on or before September 1, 2004 and Participant does not timely propose the
drilling of such Commitment Well, then El Paso will so notify Participant and
the Prospect will be no longer subject to this Agreement and Participant shall
have no further rights to earn any interests in such Prospect.



                                       6
<PAGE>
                                    SECTION 6
                                   DISCLAIMERS

6.1 INFORMATION ABOUT THE COMMITMENT WELLS. El Paso disclaims all liability and
responsibility for any representation, warranty (other than the representations
and warranties specifically set forth in this Agreement), statements or
communications (orally or in writing) to Participant, including any information
contained in any opinion, information or advice that may have been provided to
Participant by any employee, officer, director, agent, consultant, engineer or
engineering firm, trustee, representative, partner, member, beneficiary,
stockholder or contractor of El Paso wherever and however made, including those
made in any meeting, presentation, data room or internet site and any
supplements or amendments thereto or during any negotiations with respect to
this Agreement or any confidentiality agreement previously executed by El Paso
and Participant with respect to the Commitment Wells. EL PASO MAKES NO WARRANTY
OR REPRESENTATION, EXPRESS, STATUTORY OR IMPLIED, AS TO (i) THE ACCURACY,
COMPLETENESS OR MATERIALITY OF ANY DATA, INFORMATION OR RECORDS FURNISHED TO
PARTICIPANT IN CONNECTION WITH THE COMMITMENT WELLS, INCLUDING WITHOUT
LIMITATION SEISMIC DATA AND EL PASO'S INTERPRETATION AND OTHER ANALYSIS THEREOF;
(ii) THE PRESENCE, QUALITY AND QUANTITY OF HYDROCARBON RESERVES (IF ANY)
ATTRIBUTABLE TO THE COMMITMENT WELLS; (iii) THE ABILITY OF THE COMMITMENT WELLS
TO PRODUCE HYDROCARBONS, INCLUDING WITHOUT LIMITATION PRODUCTION RATES, DECLINE
RATES AND RECOMPLETION OPPORTUNITIES; (iv) THE PRESENT OR FUTURE VALUE OF THE
ANTICIPATED INCOME, COSTS OR PROFITS, IF ANY, TO BE DERIVED FROM THE COMMITMENT
WELLS; AND (v) ANY PROJECTIONS AS TO EVENTS THAT COULD OR COULD NOT OCCUR. ANY
DATA, INFORMATION OR OTHER RECORDS FURNISHED BY EL PASO ARE PROVIDED TO
PARTICIPANT AS A CONVENIENCE AND PARTICIPANT'S RELIANCE ON OR USE OF THE SAME IS
AT PARTICIPANT'S SOLE RISK.

6.2 INDEPENDENT INVESTIGATION. Participant has made its own independent
investigation, analysis and evaluation of the transactions contemplated by this
Agreement (including Participant's own estimate and appraisal of the extent and
value of the Oil and Gas reserves attributable to the Commitment Wells and the
costs to explore for and develop the reserves if found). Participant has had, or
will have prior to Closing and Participant has had or will have prior to
acceptance of this Agreement, access to all information necessary to perform its
investigation and has not relied on any representations by El Paso (other than
the representations specifically set forth in this Agreement). El Paso has
provided Participant and its experts the opportunity to review El Paso's data on
the Commitment Wells and Participant has reviewed such data that it deems
necessary. Participant understands and acknowledges that El Paso is not
guaranteeing the actual costs of other vendors supplying services to the
Commitment Wells.

6.3 NO WARRANTY OF TITLE. El Paso makes no representation or warranty of title
except El Paso warrants title against all claims by, through or under El Paso
(subject to the overriding royalty interests and other burdens described on
Exhibit "E" which El Paso has previously assigned or is obligated to assign), to
any interests in the Leases within the Prospects and shall not be responsible or
liable to Participant if El Paso's title to such interest does not exist or
fails


                                       7
<PAGE>

for any reason, including but not limited to failure to pay rentals, minimum
royalties or other lease maintenance payments or perform any condition of a
lease, or if El Paso is unable to acquire such interest.

6.4 DELAY RENTALS. During the term of this Agreement and prior to the effective
date of any Operating Agreement covering a Prospect executed by the Parties, El
Paso shall pay or tender (or cause to be paid or tendered) all rentals, minimum
royalties and other lease maintenance payments, if any, which may hereafter
become due under the terms of the said leases covered by this Agreement in such
Prospect, but shall have no liability to Participant for failure to make any
such payment or tender or to make same timely or properly, unless such failure
is due to the gross negligence or willful misconduct of El Paso. Prior to such
effective date, El Paso will be responsible for all rental costs on the Leases
within such Prospect without reimbursement from Participant. After such
effective date, all rentals on the Leases within such Prospect will be paid and
reimbursed in accordance with the terms of the respective Operating Agreements.


                                    SECTION 7
                                 TAX PARTNERSHIP

7.1 TAX PARTNERSHIP. Attached to each Operating Agreement will be a Tax
Partnership as Exhibit "G". It is the intent and the Party will take such steps
as necessary to operate these Prospects as separate Tax Partnerships, pursuant
to the Tax Partnership Agreements described herein.


                                    SECTION 8
                                   USE OF RIGS

8.1 SERVICES OF AFFILIATES OF RAMSHORN. If Participant and its affilitates
satisfy, in El Paso's reasonable opinion, El Paso's standards and requirements
as set forth below, then until October 31, 2006, El Paso will employ Participant
or its affiliates under the terms of that certain Master Drilling Contract
between Sonat Exploration Company and Nabors Drilling USA, Inc. dated August 19,
1997, as amended from time to time, or that certain IADC Drilling Contract
between Coastal Oil & Gas Corporation and Nabors Drilling USA, Inc. dated
September 15, 1997, as amended from time to time, to drill the wells covered by
this Agreement or the Operating Agreements. This Section 8.1 shall survive the
termination of this Agreement until October 31, 2006, after which time the
parties will negotiate in good faith the continued use of rigs for wells covered
by this Agreement or the Operating Agreements; provided however, neither El Paso
nor Participant shall be under any obligation to the other to enter into any
agreement regarding the use of such rigs after October 31, 2006.

To be employed in the drilling of a well (to be determined on a well by well
basis), Participant must be able to supply a quality drilling rig capable of
efficiently drilling to the proposed depth manned by competent and efficient
crews. The rig must be capable of being rigged up and ready to commence drilling
on or before El Paso's estimated spud date. If El Paso and Participant have not
agreed to drilling rates, then Participant's rates for a well must also be at


                                       8
<PAGE>

competitive rates for the type of rig, the proposed depth and the efficiency of
the rig and crew in drilling such well.

Notwithstanding anything to the contrary above, El Paso shall retain the right
to drill any well using any of the two rigs it currently has committed or under
contract with Grey Wolf.


                                    SECTION 9
                                   ASSIGNMENT

9.1 ASSIGNMENT. This Agreement may not be assigned by Participant other than to
an Affiliate. Subject to subsection 9.2 below, Participant may assign its rights
in and to any interest in a Lease that has been assigned to it by El Paso
pursuant to Section 3.3.

9.2 PREFERENTIAL RIGHT TO PURCHASE. If Participant desires to transfer, sell,
farm out, assign, or otherwise dispose of all or part of its interest in a Lease
that has been assigned to it by El Paso pursuant to Section 3.3. Participant
shall promptly give written notice to El Paso with full information about the
proposed transaction, including, but not limited to, the name and address of the
prospective transferee (who must be ready, willing, and able to acquire the
interest and deliver the stated consideration therefor), the consideration and
all terms related to the transfer. In the case of a package sale of oil and gas
interests that includes all or part of Participant's interest in such Leases, or
if the proposed transaction is structured as a non-simultaneous, like-kind
exchange under Section 1031 of the Internal Revenue Code of 1986, as amended
("Code"), the interest that is subject to this preferential right shall be
separately valued and the notice shall state the value attributed to the
interest by the prospective transferee. El Paso shall have an optional prior
right, for a period of thirty (30) days after receipt of the notice, to elect to
purchase or acquire on the same terms and conditions, or on equivalent terms for
a non-cash transaction, all of such interests that the Participant is proposing
to transfer. This preferential right shall apply separately to each Lease or
part thereof covered by this Agreement, regardless of whether it is included in
the proposed transaction along with other oil and gas interests, whether as a
sale, farm out, or non-simultaneous, like-kind exchange, and no provision in
this Agreement shall be interpreted to defeat this preferential right. Upon
exercise of this preferential right, El Paso shall agree to perform all
obligations of the prospective transferee under the proposed transaction only
for such interest subject to the proposed transaction. This preferential right,
however, shall not exist or apply when Participant proposes (a) to mortgage its
interest; (b) to dispose of or transfer its interest to an Affiliate by (i)
merger, (ii) reorganization, or (iii) consolidation; (c) to sell all, or
substantially all, of its exploration and production properties located in the
United States of America; or (d) to transfer the interest under a property
exchange transaction other than a non-simultaneous, like-kind exchange under
Section 1031 of the Code. If the proposed transaction is not consummated within
six (6) months after receipt of the notice by El Paso, the interest shall again
be governed by this subsection and the preferential right shall again arise for
the offered interest as herein described.


                                       9
<PAGE>

                                   SECTION 10
                       PARTICIPANT'S FAVORED NATION STATUS

10.1 FAVORED NATIONS. Subject to the exceptions listed below, if El Paso has
entered, or enters into a transaction prior to the completion of the Commitment
Well or the plugging and abandonment of the Commitment Well within a Prospect,
in which El Paso conveys or has conveyed any interest or any part of its
interest in any wells, leases or lands in any part of such Prospect on terms
more favorable to a third party than the terms of this Agreement pertaining to
(i) the promote (i.e. 25% for 12.5% to the Casing Point), (ii) the proportionate
costs borne on any well or (iii) the proportion of net revenue interest earned
to costs borne on any well, lease or prospect (a "Better Agreement"), then El
Paso will provide the details of such transaction to Participant. Participant
will have 15 days from the date of the receipt of such details by Participant to
elect in writing to remove such Prospect from this Agreement and enter into a
new agreement with El Paso (a "New Agreement") substantially the same as such
Better Agreement INSOFAR AND ONLY INSOFAR as the Better Agreement covers such
Prospect, with all appropriate recalculations and adjustments to be promptly
made by El Paso and Participant and all further necessary actions to be taken
promptly by El Paso and Participant to put them in the same position as if this
Agreement did not cover such Prospect ab initio and such New Agreement had been
executed contemporaneously with this Agreement. Participant's failure to respond
in writing within such 15 day period will be deemed an election not to convert
to the New Agreement on such Prospect.

Notwithstanding the foregoing paragraph, Participant shall not have the right to
elect to convert to the New Agreement on such Prospect under the following
situations:

         (i) The Better Agreement contains more favorable terms as a result of a
         reciprocal trade involving said third party's prospects, leasehold or
         wells, independent of the location of the same either within such
         Prospect or outside such Prospect, or

         (ii) The Better Agreement contains more favorable terms as a result of
         a merger, reorganization, consolidation or sale of all or substantially
         all of El Paso's assets to a subsidiary or parent company or to a
         subsidiary of a parent company, or to a company in which El Paso owns a
         majority of the stock.

10.2 TERM OF FAVORED NATIONS. The provisions of Section 10.1 shall terminate as
to each Prospect upon the completion of the Commitment Well or the plugging and
abandonment of the Commitment Well within such Prospect.

10.3 PRESENTATIONS ON FUTURE PROSPECTS. If El Paso presents a promoted prospect
to a party that is not an affiliate of El Paso prior to November 1, 2005, then
El Paso shall offer to make the same presentation on such promoted prospect to
Participant. Participant shall have five (5) business days after receipt of
notice of such presentation to elect in writing to attend a presentation of a
promoted prospect at El Paso's offices. Participant shall execute a
confidentiality agreement covering such promoted prospect before the
presentation to Participant. A failure to make an election shall be deemed to be
an election not to attend the


                                       10
<PAGE>

presentation. An election not to attend a presentation on one promoted prospect
is not a waiver of the right to attend future presentations of promoted
prospects.

Neither El Paso nor Participant shall be under any obligation to the other to
enter into any agreement on such promoted prospect.

A "promoted prospect" means one or more leases grouped together by El Paso as
potentially containing hydrocarbons in commercial quantities in one or more
geological formations in which a participant may earn an undivided interest in
such leases by paying a greater proportion of the drilling costs and other costs
than the costs attributable to the undivided interest in the leases which may be
earned by the participant.


                                   SECTION 11
                                    INSURANCE

11.1 INSURANCE. As to all operations hereunder prior to the completion of the
Commitment Well or the plugging and abandonment of the Commitment Well within a
Prospect, El Paso shall carry for the benefit and protection of the parties
hereto, the following:

     a)   Worker's Compensation as required by the laws of the state in which
          the operations are conducted and Employer's Liability insurance with
          minimum limits of $1,000,000 each accident/disease per employee.
          Worker's Compensation and Employer's Liability insurance to include
          coverage for all claims under the United State Longshoremen's and
          Harbor Worker's Act, the Jones Act, OCSLA, "in rem", and alternate
          employer/borrowed servant.

     b)   Comprehensive General Liability insurance in the amount of $5,000,000,
          including coverage for Premises/Operations, Independent Contractors,
          Personal Injury, Products/Completed Operations, Blanket Contractual
          Liability, Explosion/Collapse, Sudden and Accidental Pollution and "in
          rem".

     c)   Umbrella (excess of underlying insurance coverage mentioned above)
          with a combined limit per occurrence coverage of not less than
          $10,000,000.

To the extent permitted by law, every such insurance policy shall contain a
waiver on the part of the insurance carrier of all rights, by subrogation or
otherwise, against Participant. To the extent permitted by law, Participant
shall also be named as additional insured in each such policy.

11.2 EXCLUSION. The above insurance shall cover Participant only in its capacity
as an oil and gas lessee, as a co-owner in an oil and gas well, and as a
non-operator and shall not cover Participant as a drilling contractor or other
supplier of materials or services on an oil and gas well or related activities.


                                       11
<PAGE>

                                   SECTION 12
                                 CONFIDENTIALITY

12.1 CONTRACT AND OPERATIONS STRICTLY CONFIDENTIAL. Any information disclosed to
Participant by El Paso regarding the Prospects shall be deemed to be covered by
that certain confidentiality agreement dated April 23, 2003 by and between El
Paso and Participant. That Agreement is hereby ratified and confirmed by the
Parties.


                                   SECTION 13
                                  MISCELLANEOUS

13.1 TERM. This Agreement shall terminate on March 1, 2005 except for any
liabilities and obligations accruing on or prior to such date, which shall
survive the termination of this Agreement.

13.2 VALIDITY AND SEVERABILITY. If any provision of this Agreement is held to be
illegal, invalid or unenforceable under the present or future laws effective
during the term of this Agreement, such provision shall be fully severable; this
Agreement shall be construed and enforced as if such illegal, invalid or
unenforceable provision had never comprised a part of this Agreement; and the
remaining provisions of this Agreement shall remain in full force and effect and
shall not be affected by the illegal, invalid or unenforceable provision or by
its severance from this Agreement. In lieu of such illegal, invalid or
unenforceable provisions, there shall be added automatically as a part of this
Agreement a provision as similar in terms to such illegal, invalid or
unenforceable provision as may be possible and be legal, valid and enforceable.

13.3 NEGOTIATED INSTRUMENT. This Agreement represents a negotiated agreement and
no portion shall be construed for or against either Party by virtue of its
having been drafted by that Party.

13.4 SECURITIES ACT. Participant (a) understands that the oil and gas leases
have not been, and will not be, registered under the Securities Act of 1933 (the
"Securities Act"), or under any, state securities laws, and are being offered
and sold in reliance upon certain federal and state exemptions, (b) is acquiring
an interest in the oil and gas leases solely for Participant's own account for
investment purposes, and not with a view to the distribution thereof, (c) is a
sophisticated investor with knowledge and experience in business and financial
matters, (d) has received certain information concerning the oil and gas leases
and has had the opportunity to obtain additional information as desired to
evaluate the merits and the risks inherent in holding an interest in the oil and
gas leases, (e) is able to bear the economic risk and lack of liquidity inherent
in holding an interest in the oil and gas leases, and (f) is an accredited
investor as defined in Regulation D promulgated under the Securities Act.

13.5 WAIVER OF DECEPTIVE TRADE PRACTICES ACTS. PARTICIPANT WAIVES ITS RIGHTS
UNDER THE DECEPTIVE TRADE PRACTICES ACT SECTION 17.41 et seq., TEXAS BUSINESS &
COMMERCE CODE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS, AND UNDER SIMILAR
STATUTES ADOPTED IN OTHER STATES, TO THE EXTENT THEY HAVE APPLICABILITY TO THE
TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. AFTER CONSULTATION WITH AN ATTORNEY
OF ITS SELECTION, PARTICIPANT CONSENTS TO THIS WAIVER.

                                       12
<PAGE>

13.6 GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN
ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS. NOT INCLUDING, HOWEVER, ANY OF
ITS CONFLICTS OF LAW RULES WHICH WOULD DIRECT OR REFER TO THE LAWS OF ANOTHER
JURISDICTION.

13.7 AMENDMENTS. Any amendment hereto shall become effective only upon the
express written consent of El Paso and Participant, at which time it shall
become effective as to all Party hereto. No amendment, modification or
alteration of the terms hereof shall be binding unless the same is in writing
and is in accordance with this subsection.

13.8 NOTICES. Except as otherwise expressly provided in this Agreement, all
notices, payments, demands, requests or other communications required or
permitted to be given pursuant to this Agreement shall be in writing and may be
given either (i) in person, (ii) by United States mail, certified or registered,
return receipt requested, postage prepaid, (iii) by prepaid telegram, telex,
cable, telecopy, or similar means (with signed confirming copy to follow by
mail), or (iv) by any other method permitted by law, as follows:

         IF TO EL PASO:                     IF TO PARTICIPANT

         Nine Greenway Plaza                515 W. Greens Road, Suite 1000
         Houston, Texas  77046              Houston, Texas 77067
         Attention:  J. T. Elzner           Attention: J.R. "Digger" Smith
         Telephone:  832.676.7817           Telephone: 281 775 8527
         Fax:  832.676.1353                 Fax: 281 775 8414

                                            With copy to:

                                            Law Department
                                            515 W. Greens Road, Suite 1000
                                            Houston, Texas 77067
                                            Attention: Bruce M. Taten
                                            Telephone: 281 775 8556
                                            Fax: 281 775 8431

14.9 ENTIRE AGREEMENT. This Agreement, its Exhibits, and other documents
executed in accordance with this Agreement constitute the entire agreement of
the parties with respect to the subject matter hereof.

Executed as of the date first written above.

                                          El Paso Production Company

                                          By: /s/ Jon R. Nelsen
                                              ----------------------------------
                                              Jon R. Nelsen, Attorney in Fact


                                       13
<PAGE>

                                          Ramshorn Investments, Inc.


                                          By: /s/ Jordan R. Smith
                                              ----------------------------------
                                          Name: Jordan R. Smith
                                              ----------------------------------
                                          Title: President
                                                 -------------------------------


                                       14

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12
<SEQUENCE>7
<FILENAME>h13476exv12.txt
<DESCRIPTION>COMPUTATION OF RATIOS
<TEXT>
<PAGE>
                                                                      EXHIBIT 12

                    NABORS INDUSTRIES, LTD. AND SUBSIDIARIES
               COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
                      (In thousands, except ratio amounts)


<Table>
<Caption>


                                                             Year Ended December 31,
                                                    ------------------------------------------
                                                       2003            2002            2001
                                                    ----------      ----------      ----------
<S>                                                 <C>             <C>             <C>
Income before income taxes                          $  174,623      $  140,774      $  557,612
Less earnings from affiliates, net of dividends           (919)         (4,900)        (15,833)
Add amortization of capitalized interest                   896             843             768
Add fixed charges as adjusted (from below)              74,107          70,341          63,774
                                                    ----------      ----------      ----------
   Earnings                                         $  248,707      $  207,058      $  606,321
                                                    ----------      ----------      ----------

Fixed charges:
 Interest expense:
   Interest on indebtedness                         $   39,585      $   31,156      $   22,921
   Capitalized                                             903           1,125           1,609
 Amortization of debt related costs (1)                 31,155          35,912          37,801
 Interest portion of rental expense                      3,367           3,273           3,052
                                                    ----------      ----------      ----------
 Fixed charges before adjustments                       75,010          71,466          65,383
 Less capitalized interest                                (903)         (1,125)         (1,609)
                                                    ----------      ----------      ----------
 Fixed charges as adjusted                          $   74,107      $   70,341      $   63,774
                                                    ----------      ----------      ----------

Ratio (earnings divided by fixed charges
 before adjustments)                                      3.32            2.90            9.27
                                                    ----------      ----------      ----------
</Table>


(1) Includes deferred financing, discount and premium amortization.




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>8
<FILENAME>h13476exv13.txt
<DESCRIPTION>2003 ANNUAL REPORT
<TEXT>
<PAGE>
                                                                      EXHIBIT 13

                                (BEAUTY PICTURE)


the BEAUTY
of our
Composition


NABORS INDUSTRIES
2003 ANNUAL REPORT


<PAGE>

                                 (DOT PICTURE)


<PAGE>


                            our many options create
                                  a canvas of

                                  opportunity

1  a Study of Supply on Demand

2  the Scale of our Footprint

3  a Well-Oiled Machine

4  a More Balanced Sheet

                                    nbr {01}


<PAGE>

1 the BEAUTY of our Composition

                                (FAUCET PICTURE)


                                  nbr {02-03}


<PAGE>



An available inventory of premium rigs in a variety of styles and sizes is
readily translatable from one market to another, ensuring that Nabors can
respond rapidly to customer demand at an advantageous cost.

                                   ON DEMAND


<PAGE>

2 the BEAUTY of our Composition


                       the SCALE of our global footprint



Years of operating in more than 50 countries has resulted in a global
infrastructure of facilities and personnel and a level of local know-how that
makes responding to worldwide customer demand not only possible but predictable.

                                  nbr {04-05}


<PAGE>

                           (GLOBAL FOOTPRINT PICTURE)

<PAGE>

a WELL-OILED machine

The breadth of our experience in every geographic area and an organization
saturated with technical, operational, logistical and financial expertise gives
Nabors a significant competitive advantage and provides a springboard from which
to add to a growing track record of success.

                    (PICTURE OF TWO MEN LOOKING AT A MOSAIC
                  OF A PICTURE OF TOP DRIVES AND A RIG FLOOR)



<PAGE>


3 the BEAUTY of our Composition


                           (MOSAIC OF A PICTURE OF A
                                WORKER ON A RIG)


                                  nbr {06-07}


<PAGE>

4 the BEAUTY of our Composition


                                (PENCIL PICTURE)


                                  nbr {08-09}


<PAGE>

                                     a more

                                       B
                                       A
                                       L
                                       A
                                       N
                                       C
                                       E
                                       D

                                       S
                                       H
                                       E
                                       E
                                       T

Recent growth in our Canadian and international markets along with improvements
in our cost of capital, tax rate and diluted share count have given Nabors
higher and more sustainable earnings potential than we previously enjoyed at
significantly lower levels of U.S. activity.


<PAGE>

                              FINANCIAL HIGHLIGHTS

                    Nabors Industries Ltd. and Subsidiaries

Operating Data

<Table>
<Caption>
                                                                                         TWELVE
                                                                                         MONTHS
                                                                                         ENDED
                                                                                       DECEMBER 31,
                                          YEAR ENDED DECEMBER 31,                      (UNAUDITED)        YEAR ENDED SEPTEMBER 30,
                       -----------------------------------------------------------     ------------    ---------------------------
(IN THOUSANDS,
EXCEPT PER SHARE          2003            2002           2001             2000            1999           1998             1997
AMOUNTS AND RATIO
DATA)
<S>                    <C>             <C>             <C>             <C>             <C>             <C>             <C>
Operating revenues
  and Earnings
  from unconsoli-
  dated affiliates     $ 1,890,186     $ 1,481,218     $ 2,228,070     $ 1,414,943     $   670,186     $ 1,007,864     $ 1,115,032
Depreciation and
  amortization,
  and depletion            235,127         195,365         189,896         152,413          99,893          84,949          72,350
Net income                 192,228         121,489         357,450         137,356          27,704         124,988         136,020
Earnings per
  diluted share        $      1.25     $       .81     $      2.24     $       .90     $       .23     $      1.16     $      1.24
Weighted average
  number of
  diluted com-
  mon shares
  outstanding              156,897         149,997         168,790         152,417         120,449         112,555         113,793
Capital expendi-
  tures and
  acquisitions
  of businesses        $   357,393     $   702,843     $   803,241     $   334,279     $   837,732     $   315,057     $   381,196
Interest
  coverage ratio           6.8 : 1         6.0 : 1        13.3 : 1        11.8 : 1         5.8 : 1        19.4 : 1        18.3 : 1



<Caption>

                                   YEAR ENDED SEPTEMBER 30,
                       -------------------------------------------
(IN THOUSANDS,
EXCEPT PER SHARE           1997            1996              1995
AMOUNTS AND RATIO
DATA)
<S>                    <C>              <C>            <C>
Operating revenues
  and Earnings
  from unconsoli-
  dated affiliates     $ 1,029,303     $   719,743     $   572,788
Depreciation and
  amortization,
  and depletion             66,391          46,117          31,042
Net income                 114,808          70,500          51,104
Earnings per
  diluted share        $      1.08     $       .75     $       .57
Weighted average
  number of
  diluted com-
  mon shares
  outstanding              111,975          93,752          89,655
Capital expendi-
  tures and
  acquisitions
  of businesses        $   399,895     $   177,925     $   144,560
Interest
  coverage ratio          16.1 : 1        11.7 : 1        12.8 : 1
</Table>


                                  nbr {10-11}


<PAGE>

Balance Sheet Data

<Table>
<Caption>


                                                           AS OF DECEMBER 31,
                     -------------------------------------------------------------------------------------------------
(IN THOUSANDS,            2003             2002            2001              2000             1999            1998
EXCEPT RATIO DATA)
<S>                  <C>              <C>              <C>              <C>              <C>              <C>
Cash and cash
  equivalents,
  and short-term
  and long-term
  marketable
  securities         $  1,532,090     $  1,330,799     $    918,637     $    550,953     $    111,666     $     47,340
Working capital           917,274          618,454          700,816          524,437          195,817           36,822
Property, plant
  and equip-
  ment, net             2,990,792        2,801,067        2,451,386        1,835,039        1,678,664        1,127,154
Total assets            5,602,692        5,063,872        4,151,915        3,136,868        2,398,003        1,465,907
Long-term debt          1,985,553        1,614,656        1,567,616          854,777          482,600          217,034
Shareholders'
  equity             $  2,490,275     $  2,158,455     $  1,857,866     $  1,806,468     $  1,470,074     $    867,469
Funded debt to
  capital ratio:
  Gross                  0.48 : 1         0.49 : 1         0.46 : 1         0.32 : 1         0.25 : 1         0.26 : 1
  Net                    0.23 : 1         0.26 : 1         0.26 : 1         0.15 : 1         0.20 : 1         0.17 : 1

<Caption>

                         AS OF
                      DECEMBER 31,
                      (UNAUDITED)                AS OF SEPTEMBER 30,
                     ------------     ----------------------------------------------
(IN THOUSANDS,            1997            1997              1996              1995
EXCEPT RATIO DATA)
<S>                  <C>              <C>              <C>              <C>
Cash and cash
  equivalents,
  and short-term
  and long-term
  marketable
  securities         $     42,135     $     53,323     $    115,866     $     24,979
Working capital            62,571           70,872          172,091           33,892
Property, plant
  and equip-
  ment, net               923,402          861,393          511,203          393,464
Total assets            1,281,306        1,234,232          871,274          593,272
Long-term debt            226,299          229,507          229,504           51,478
Shareholders'
  equity             $    767,340     $    727,843     $    457,822     $    368,750
Funded debt to
  capital ratio:
  Gross                  0.27 : 1         0.27 : 1         0.35 : 1         0.20 : 1
  Net                    0.20 : 1         0.20 : 1         0.21 : 1         0.09 : 1

</Table>



Geographic Distribution of Revenues and Assets

<Table>
<Caption>



                                                     YEAR ENDED DECEMBER 31,
                     -------------------------------------------------------------------------------------------------
(IN THOUSANDS)            2003            2002             2001              2000            1999              1998
<S>                   <C>              <C>             <C>              <C>              <C>               <C>

Operating
  revenues and
  Earnings from
  unconsolidated
  affiliates:
  United States      $  1,152,272     $  1,012,503     $  1,859,356     $  1,115,899     $    448,478     $    706,046
  Foreign                 737,914          468,715          368,714          299,044          221,708          301,818
                     ------------     ------------     ------------     ------------     ------------     ------------
                     $  1,890,186     $  1,481,218     $  2,228,070     $  1,414,943     $    670,186     $  1,007,864
                     ------------     ------------     ------------     ------------     ------------     ------------
<Caption>

                       TWELVE
                     MONTHS ENDED
                     DECEMBER 31,
                     (UNAUDITED)                YEAR ENDED SEPTEMBER 30,
                     ------------     ----------------------------------------------
(IN THOUSANDS)           1997            1997              1996              1995
<S>                  <C>             <C>              <C>              <C>
Operating
  revenues and
  Earnings from
  unconsolidated
  affiliates:
  United States          867,999     $    797,319     $    503,622     $    383,376
  Foreign                247,033          231,984          216,121          189,412
                      ----------     ------------     ------------     ------------
                      $1,115,032     $  1,029,303     $    719,743     $    572,788
                      ----------     ------------     ------------     ------------
</Table>


<Table>
<Caption>
                                                                                                                      AS OF
                                                                                                                    DECEMBER 31,
                                                        AS OF DECEMBER 31,                                          (UNAUDITED)
                    -------------------------------------------------------------------------------------------     -----------
(IN THOUSANDS)          2003            2002            2001            2000            1999           1998             1997
<S>                 <C>             <C>             <C>             <C>             <C>             <C>             <C>
Total assets:
  United States     $ 2,373,210     $ 3,569,657     $ 3,282,429     $ 2,649,923     $ 1,917,751     $ 1,068,193     $   958,026
  Foreign             3,229,482       1,494,215         869,486         486,945         480,252         397,714         323,280
                    -----------     -----------     -----------     -----------     -----------     -----------     -----------
                    $ 5,602,692     $ 5,063,872     $ 4,151,915     $ 3,136,868     $ 2,398,003     $ 1,465,907     $ 1,281,306
                    -----------     -----------     -----------     -----------     -----------     -----------     -----------

<Caption>


                                AS OF SEPTEMBER 30,
                     -------------------------------------------
(IN THOUSANDS)          1997             1996             1995

<S>                  <C>             <C>             <C>
Total assets:
  United States      $   897,453     $   593,014     $   348,248
  Foreign                336,779         278,260         245,024
                     -----------     -----------     -----------
                     $ 1,234,232     $   871,274     $   593,272
                     -----------     -----------     -----------
</Table>


<PAGE>

                         the BEAUTY of our Composition
(FAUCET PICTURE)

SUPPLY on demand


o        Nabors has systematically assembled a fleet of premium rigs in
         virtually every size, depth and style, allowing the company to meet
         customer demand wherever it occurs.


                           Worldwide Rig Availability

                                224 Working 308
      (GRAPH)                                                      (GRAPH)
                               330 Available 229

                                94 Inventory 102
       2002                                                         2003

o        Nabors maintains the industry's largest inventory of major rig
         components, allowing the activation, modification or repair of rigs for
         any application quickly and at minimum incremental cost.

o        Nabors has the worldwide manufacturing capability to configure rigs to
         customer specifications from existing inventory, delivering even
         highly-specialized rigs economically and in minimal time.

o        A continuous upgrade program has improved the marketability of Nabors
         rigs, keeping them at the forefront of advancements in rig efficiency
         and economy.

                           (GLOBAL FOOTPRINT PICTURE)

                        the SCALE of our global footprint

o        With an operating history in approximately 50 countries, Nabors has
         built a worldwide support infrastructure that facilitates the pursuit
         of opportunities in any market.

         954      LAND WORKOVER RIGS

         575      LAND DRILLING RIGS

         45       PLATFORMS

         31       MARINE VESSELS

         16       JACK-UPS

         3        BARGE RIGS

         *        TOP DRIVE MANUFACTURING

         *        DRILLING INSTRUMENTATION SYSTEMS

         *        OILFIELD SERVICES

o        Nabors can add, modify or upgrade rigs at multiple facilities
         worldwide, allowing the Company to quickly add incremental capacity in
         any geographic region.

o        Nabors' success internationally is the result of developing a critical
         mass infrastructure, extensions of which can easily be added to support
         expansion into new markets.

o        Nabors is continually recruiting and training local nationals within
         the countries in which we operate - in the process reducing our cost of
         doing business while contributing significantly to the local economy.


                                  nbr {12-13}





<PAGE>

                          the BEAUTY of our Composition

                             (PICTURE OF A WORKER)

                              a WELL-OILED machine


o        Nabors has always placed a high priority on recruiting and retaining
         qualified people at every level of the organization and in every
         country in which we operate.

o        An emphasis on training and a commitment to safety have resulted in
         consistently excellent performance by Nabors rigs and crews,
         establishing the Company as the world's premiere drilling contractor.

                        (GRAPH OF OSHA RECORDABLE RATE)

o        An emphasis on developing or acquiring important new technologies and
         applying them appropriately has kept Nabors on the cutting edge of
         drilling achievement.

o        Nabors' financial acumen and opportunistic culture have resulted in a
         growth strategy that has been consistently successful in virtually any
         market conditions.

                                (PENCIL PICTURE)

                              a more BALANCED sheet

o        Increased contributions from our Canadian and International operations,
         which collectively now approximate 65 percent of our adjusted income
         from operating activities, have given Nabors a more balanced operating
         line that was once dominated by U.S. land drilling activity.

o        Timely refinancing has steadily reduced the cost of capital for Nabors,
         with our most recent transaction trimming 8.1 million shares from our
         diluted share count and funding an April 2004 redemption, which will
         save $20 million in annualized interest.

o        Nabors continues to benefit from our decision to reorganize as a
         Bermuda company, which has facilitated growth in our international
         businesses, improved access to foreign capital markets, lowered our
         effective worldwide tax rate and contributed to the employment of over
         2,000 U.S. citizens.

o        While Nabors' capital structure, total assets and shareholder equity
         continue to improve, a stronger-than-ever cash position provides the
         flexibility to capitalize on prospective opportunities.


<PAGE>

                                    creating
                      a company of aesthetic and intrinsic

                                (VALUE PICTURE)
                                     value

                                  nbr {14-15}




<PAGE>

                             LETTER TO SHAREHOLDERS

         The timeliness of our recent Canadian acquisitions was emphatically
demonstrated in 2003 as record contributions from this unit, combined with
improved performance in several of our other operations, fueled the second best
year in the Company's history. This is particularly noteworthy considering that
our largest component, U.S. Land Drilling, was substantially below the level we
expect to see in the near future. The breadth of the year's overall growth
demonstrates the increased earnings potential the Company now enjoys and the
improved balance in our income stream.

Strategic actions taken to improve the non-operational aspects of our business
added materially to the Company's increased profitability in 2003. Since our
reorganization, business has steadily improved contributing to the employment of
an additional 2,000 U.S. citizens. In June, we effected a significant reduction
in our average cost of capital and weighted average shares with the issuance of
non-interest bearing, no yield convertible debt. A portion of the proceeds of
this new issue were used to redeem higher cost convertible debt, reducing by
eight million our average diluted share count. In April 2004, we expect to
utilize the balance of these proceeds to redeem a maturing higher cost issue,
saving over $20 million in annualized interest. Additionally, our mid-2002
reorganization as a Bermuda corporation has further improved income and
diminished the competitive advantages previously enjoyed by our non-U.S. based
competitors.


<PAGE>

In addition to the inherent competitive advantages of our financial position,
the Company's global infrastructure and available premium asset inventory played
an even bigger role in our ability to realize a higher success rate in securing
incremental work throughout our various markets in 2003. This was particularly
true in our U.S. Lower 48 Land Drilling unit where we garnered 35 percent of the
year-over-year increase in the Baker Hughes rig count, nearly double our 2002
market share. This was due to an increase in the number of technically complex
directional and horizontal wells that our customers undertook in several
regions, which spurred demand for our more sophisticated electric rigs,
especially those with upgraded mud pumps and power. A second quarter surge in
activity in the Rocky Mountain region caused demand for 1,000-horsepower rigs to
outstrip availability, providing an opportunity for Nabors to significantly
increase our market share in that area by relocating excess capacity from our
mid-continent fleet. These strategic actions were accomplished with minimal
incremental investment.

Nabors continued to leverage these same competitive advantages in our
international markets by capitalizing on a substantial increase in demand for
offshore platform drilling rigs. The Company responded to this opportunity by
modifying and redeploying eight underutilized rigs from our U.S. Gulf of Mexico
operation, five to Mexico and one each to India, Indonesia and the eastern
Mediterranean. The Indian contract represented a new market for Nabors, as did
the securing of an initial contract to provide management oversight of drilling
operations for a major Russian operator, both of which have the


<PAGE>

                                   Baker Hughes Nabors Area vs. Nabors Rig Count
         Source: Baker Hughes (excludes northeast states, California and Alaska)


                                    (GRAPH)



                                  nbr {16-17}

<PAGE>


potential to be strategic markets long term. The export of these rigs had the
corollary benefit of balancing supply and demand for this class of rig in the
U.S. Gulf of Mexico market, leading to improved utilization and pricing.

Our large rig and component inventory was also utilized to build three
state-of-the-art rigs in the U.S. and two in Canada at well below the costs
associated with new construction, allowing us to generate superior returns at
today's market rates. Two of the U.S. rigs utilized long-idle 1,500-horsepower
rigs that were remodeled and transformed into uniquely compact skidded rigs for
close well center development in an environmentally sensitive area of the Rocky
Mountains. The two Canadian rigs incorporated an innovative design that
represented a step-change in drilling and moving efficiency.

Nabors is also upgrading our existing fleet to realize similar improvements in
drilling and moving efficiency, a step that is already yielding positive results
with customers as well as superior returns on these investments. As a result,
our average rig moving times are steadily improving and we continue to
selectively incorporate larger mud pumps and power systems to accommodate the
higher hydraulic horsepower requirements of today's newer bits and drilling
motors. We are also accelerating our implementation of the OptiDrill(TM)
automatic driller system which significantly improves drilling efficiency, and
have recently completed the fleet-wide implementation of rig performance and
operating data transmission via the Internet.



                                  nbr {18-19}

<PAGE>


We remain steadfast in our conviction that we are in the midst of a long-term,
steady growth cycle that has been and will continue to be underpinned by the
enduring supply challenges associated with global oil and, more particularly,
North American natural gas. It is our opinion that while there are a number of
potential alternatives for natural gas, the regulatory, economic and technical
challenges associated with their development dictate that it will be at least a
decade before they adversely impact the economics of more aggressive drilling as
the most viable source of supply in North America. The continued growth of
global oil demand despite higher oil prices and the impending decline of many of
the world's major fields augurs for an even longer duration of additional
drilling as the primary source of global oil supply.

All of this implies continued growth prospects throughout all of our global
businesses, especially those most influenced by North American natural gas. The
breadth of our involvement in virtually all of the world's more significant oil
and gas producing markets and the quantity of premium rigs we can deploy at
favorable cost put us in an excellent if not unique position to capture an
increasing share of incremental work. Just as these competitive advantages have
been demonstrated in 2003, they are becoming an even bigger factor in our
near-term outlook as anecdotal evidence of an improving market has recently
become more tangible.

Near term, the largest contribution to our growth should come from our U.S.
Lower 48 Land Drilling unit, where activity levels are substantially higher than
last year and improvement in pricing is beginning to


<PAGE>

15%
         Canada and
         International
45%


36%
         All other
         U.S.
         Businesses
33%


49%
         U.S. Lower 48
         Land Drilling

22%

                                    (GRAPH)
                               Prior Best Year -
                            2001 Actual Distribution



                                     (GRAPH)
                               Current Projected
                            Distribution at 2001 EPS

                                                                           $2.24
                                              2001 Prior Best Earnings Per Share

Distribution of
adjusted income
derived from
operating
activities

                                                       improved business balance

                                  nbr {20-21}


<PAGE>

be realized in selective markets and asset classes. Our U.S. Gulf of Mexico
offshore business should also be a major component of the year's growth, with
its contribution expected to approach the record level of 2001. This outlook
stems from the tightening supply of platform rigs, which accompanied our export
last year of several of these rigs to international markets, and a more
favorable environment for our smaller workover and jack-up rigs. The deployment
of three new MODS platform rigs, which we were able to construct from our
available equipment at well below competitive costs, will be strongly additive
to this unit's performance, a reflection of the enthusiasm with which our
customers have embraced this innovative rig.

The robust Canadian market that materialized throughout 2003 should further
expand with higher average pricing and utilization. Our international business
should steadily improve as a full year's contribution from the offshore rig
deployments of mid-2003 combine with a general increase in utilization of the
established fleet.

At present, only our Alaska operation is expected to report lower results. The
completion of two long-term contracts and a generally lackluster drilling
environment should lead to substantially lower profitability, although this unit
represents a much smaller portion of our business than in previous years.

Clearly, Nabors has reason for optimism in the coming year. Growth in our
various businesses other than U.S. Lower 48 Land Drilling has produced
increasingly significant contributions to our results, ensuring


<PAGE>


                                                             Anthony G. Petrello
                                                  Deputy Chairman, President and
                                                         Chief Operating Officer

                                                              Eugene M. Isenberg
                                                                    Chairman and
                                                         Chief Executive Officer

                   (PICTURE OF MR. ISENBERG AND MR. PETRELLO)

a more balanced income stream and even larger ultimate earnings potential. When
this enhanced balance is combined with our improved cost of capital, diluted
share count and tax position, Nabors' earnings can surpass 2001's record level
with only half the contribution we previously derived from our U.S. land
drilling business.

The one constant in all of this is Nabors' commitment to quality, efficiency and
safety. This is reflected in our continual search for and subsequent adoption of
the most cost-effective technologies and best practices, and our relentless
drive to improve on what are already industry-best safety records. As we
continue to incorporate these standards into our business, we will continue to
meet or exceed our customers' expectations, laying the groundwork for sustained
excellence in our performance and delivering the value you have come to expect
from your investment in Nabors.

                                   Sincerely,

                             /s/ EUGENE M. ISENBERG

                               EUGENE M. ISENBERG
                      Chairman and Chief Executive Officer

<PAGE>

                              the landscape of our

                                   OPERATIONS

Nabors has built a position of preeminence in oil and gas drilling and workover
throughout most of the world's more important oil and gas regions. As a
collective whole, Nabors possesses significant competitive strengths through the
sharing of certain attributes among its various subsidiaries. Nabors' strong
financial position, available asset base, global infrastructure and extensive
know-how resident in its capable staff provide it with the ability to respond to
nearly any customer requirement in any area of the globe.

                                  nbr {22-23}

<PAGE>
           (PICTURE OF TWO WOMEN LOOKING AT A PICTURE OF A TOP DRIVE)


                                  nbr {24-25}
<PAGE>

                        (PICTURE OF A RIG AND LANDSCAPE)
<PAGE>

       (PICTURE OF A MAN LOOKING AT A PICTURE OF AN OFFSHORE JACK-UP RIG)
<PAGE>
                   (THREE PICTURES OF WORKERS AND DRILL PIPE)


                                  nbr {26-27}

<PAGE>
                  (PICTURE OF AN OFFSHORE PLATFORM STRUCTURE)

                                  nbr {28-29}
<PAGE>

         (PICTURE OF A MAN LOOKING AT A PICTURE OF A JACK-UP RIG DECK)
<PAGE>
                       (PICTURE OF AN ARCTIC RIG MOVING)

                                  nbr {30-31}


<PAGE>

                  (PICTURE OF FOUR CAMELS AND A CAMEL JOCKEY)

<PAGE>


                       figure study: the elements of our

                                   OPERATIONS

         Nabors has established operations in most of the world's more important
         oil and gas regions. Our business is organized into a group of
         semi-autonomous operating subsidiaries along geographic and product
         lines. All units benefit from the resources and expertise of the parent
         corporation and their affiliated companies.

                                  nbt (32-33)
<PAGE>

                          (CHART OF NABORS' STRUCTURE)



Figure 1

                                    Peak Oilfield Services
                                       Ryan Energy Technologies
                                           Epoch Well Services, Inc.
                                              Canrig Drilling Technology, Ltd.
                                                 Marine Transportation


        U.S. Land                             Other
     Well-Servicing                    Operating Segments


    U.S. Offshore         Oil and Gas            International



       U.S. Land                           Canada
        Drilling


     Alaska Drilling


     U.S. Lower 48 Land
          Drilling


                                                               Nabors Industries

<PAGE>

                   (MAP OF WORLD WITH NABORS' RIG LOCATIONS)






Figure 2






                                  16 Jack-Ups


                                                               575 Land Drilling
                                                                     Rigs




                                                               * Top Drive
                                                                 Manufacturing
45 Platforms
                                                               * Drilling
                                                                 Instrumentation
                                                                 Systems
                                  3 Barge Rigs
                                                               * Oilfield
                                                                 Services





                                              31 Marine Vessels





954 Land Workover Rigs
<PAGE>
Figure 3

                                RIG FLEET STATUS


Offshore Rig Fleet

<Table>
<Caption>
                                                          PLATFORM WORKOVER                                 PLATFORM DRILLING
                              -------------------------------------------------------------------------  ------------------------
                                                                                             Super                        Self-
                               Concentric     < 750 HP      Sundowner(R)     > 750 HP      Sundowner(R)      MASE(R)    Elevated
                              -------------  -------------  -------------  -------------  -------------  -------------  ---------
<S>                           <C>            <C>            <C>            <C>            <C>            <C>            <C>
INTERNATIONAL OFFSHORE
         Australia                                                                     1
         Brazil
         Congo                                                                                        1
         Indonesia                                                                                                   1
         India                                                          1
         Italy                                                                                        1
         Malaysia                                                                      1
         Mexico                                                                                       3              1          1
         Qatar
         Saudi Arabia
         Trinidad                                                                                                    1
         United States                                                                                                          1
                              -------------  -------------  -------------  -------------  -------------  -------------  ---------
TOTAL INTERNATIONAL OFFSHORE              0              0              1              2              5              3          2
                              -------------  -------------  -------------  -------------  -------------  -------------  ---------
U.S. Gulf of Mexico                       3              3              7              3              3              0          6
Alaska                                                                                                                          1
California                                                                                                                      2
                              -------------  -------------  -------------  -------------  -------------  -------------  ---------
TOTAL OFFSHORE                            3              3              8              5              8              3         11

<Caption>
                                PLATFORM
                                DRILLING
                              -------------                    Workover      Drilling
                                   API           Barge         Jack-up       Jack-up          Total
                              -------------  -------------  -------------  -------------  -------------
<S>                           <C>            <C>            <C>            <C>            <C>
INTERNATIONAL OFFSHORE
         Australia                                                                                    1
         Brazil                                                                        1              1
         Congo                                                                                        1
         Indonesia                                                                                    1
         India                                                                                        1
         Italy                                                                                        1
         Malaysia                                                                                     1
         Mexico                                                                        1              6
         Qatar                                                                         1              1
         Saudi Arabia                                                                2.5            2.5
         Trinidad                                                                      1              2
         United States                                                                 1              2
                              -------------  -------------  -------------  -------------  -------------
TOTAL INTERNATIONAL OFFSHORE              0              0              0            7.5           20.5
                              -------------  -------------  -------------  -------------  -------------
U.S. Gulf of Mexico                       4              3              7              1             40
Alaska                                                                                                1
California                                                                                            2
                              -------------  -------------  -------------  -------------  -------------
TOTAL OFFSHORE                            4              3              7            8.5           63.5
</Table>

Workover/Well-Servicing Rigs

<Table>
<Caption>
                                 < 300 HP     300-350 HP    400-450 HP   500 HP and >      Total
                                -----------   -----------   -----------  ------------   -----------
<S>                             <C>           <C>           <C>          <C>            <C>
U.S. LOWER 48
         West Texas                       7            74            67             8           156
         East Texas                       1             8            14             6            29
         South Texas                      0            12            13             7            32
         Oklahoma                         3             7            17            10            37
         Rocky Mountain                   1             6            29             8            44
         California                      63            74            59             5           201
         Stacked                         33           159            40            12           244
TOTAL U.S. LOWER 48                     108           340           239            56           743
CANADA                                   16           126            60             9           211
TOTAL WORKOVER/WELL-SERVICING           124           466           299            65           954
</Table>

                                   nbr {34-35}


<PAGE>
Land Drilling Fleet

<Table>
<Caption>
                                           < 1,000 HP            1,000 - 1,399 HP
                                      ---------------------   ---------------------
                                       SCR    Other   Total    SCR    Other   Total
                                      -----   -----   -----   -----   -----   -----
<S>                                   <C>     <C>     <C>     <C>     <C>     <C>
ALASKA
   North Slope                            1       1       2       4       0       4
   Cook Inlet                             0       1       1       0       0       0
   Joint Venture                          0       1       1       0       0       0
                                      -----   -----   -----   -----   -----   -----
Total Alaska                              1       3       4       4       0       4
                                      -----   -----   -----   -----   -----   -----
U.S. LOWER 48
   Southern Division
    California                            3       4       7       3       0       3
    East Texas                            4       7      11      17       7      24
    Gulf Coast                            0       0       0       0       2       2
    South Texas                           0       1       1       1       5       6
    West Texas                            1       9      10       4       3       7
                                      -----   -----   -----   -----   -----   -----
    Subtotal Southern Division            8      21      29      25      17      42
                                      -----   -----   -----   -----   -----   -----
   Northern Division
    Mid-continent                         0      18      18       8      16      24
    North Dakota                          0       4       4       1      12      13
    Wyoming                               5      14      19       3       6       9
                                      -----   -----   -----   -----   -----   -----
    Subtotal Northern Division            5      36      41      12      34      46
                                      -----   -----   -----   -----   -----   -----
    Subtotal Active Fleet                13      57      70      37      51      88
                                      -----   -----   -----   -----   -----   -----
    Stacked Inventory                     6      42      48       3      22      25
                                      -----   -----   -----   -----   -----   -----
    Subtotal U.S. Lower 48               19      99     118      40      73     113
                                      -----   -----   -----   -----   -----   -----
TOTAL U.S. LAND DRILLING FLEET           20     102     122      44      73     117
                                      -----   -----   -----   -----   -----   -----
CANADA                                    5      51      56      10       3      13
                                      -----   -----   -----   -----   -----   -----
INTERNATIONAL

   Latin America

    Argentina                             0      10      10       3       2       5
    Bolivia                               0       0       0       0       2       2
    Colombia                              0       3       3       0       1       1
    Ecuador                               0       5       5       0       2       2
    Venezuela                             1       1       2       0       0       0
                                      -----   -----   -----   -----   -----   -----
    Subtotal Latin America                1      19      20       3       7      10
                                      -----   -----   -----   -----   -----   -----
   Australia and Far East
    Australia                             0       4       4       0       0       0
    Indonesia                             0       2       2       0       0       0
                                      -----   -----   -----   -----   -----   -----
    Subtotal Australia and Far East       0       6       6       0       0       0
                                      -----   -----   -----   -----   -----   -----
   Middle East/Africa/CIS
    Algeria                               0       0       0       0       0       0
    Kazakhstan                            1       2       3       0       0       0
    Oman                                  0       0       0       2       0       2
    Saudi Arabia                          0       0       0       0       0       0
    U.A.E                                 0       4       4       0       0       0
    Yemen                                 0       3       3       1       1       2
                                      -----   -----   -----   -----   -----   -----
    Subtotal Middle East/Africa/CIS       1       9      10       3       1       4
                                      -----   -----   -----   -----   -----   -----
Joint Venture
   Saudi Arabia                           0      11      11       0       0       0
   Oman                                   0       0       0       1       0       1
                                      -----   -----   -----   -----   -----   -----
    Subtotal Joint Ventures               0      11      11       1       0       1
                                      -----   -----   -----   -----   -----   -----
TOTAL INTERNATIONAL                       2      45      47       7       8      15
                                      -----   -----   -----   -----   -----   -----
TOTAL GLOBAL LAND DRILLING FLEET         27     198     225      61      84     145
                                      -----   -----   -----   -----   -----   -----
</Table>



                                   nbr {36-37}
<PAGE>
<Table>
<Caption>
                                        1,400 - 1,999 HP           > 2,000 HP                Total
                                      ---------------------   ---------------------   ---------------------
                                       SCR    Other   Total    SCR    Other   Total    SCR    Other   Total
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
<S>                                   <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>
ALASKA
   North Slope                            0       0       0       9       0       9      14       1      15
   Cook Inlet                             1       0       1       1       0       1       2       1       3
   Joint Venture                          0       0       0       0       0       0       0       1       1
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
Total Alaska                              1       0       1      10       0      10      16       3      19
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
U.S. LOWER 48
   Southern Division
    California                            5       0       5       5       0       5      16       4      20
    East Texas                           13       2      15       5       0       5      39      16      55
    Gulf Coast                            5       1       6      18       2      20      23       5      28
    South Texas                          15       6      21      10       1      11      26      13      39
    West Texas                            1       2       3       4       0       4      10      14      24
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
    Subtotal Southern Division           39      11      50      42       3      45     114      52     166
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
   Northern Division
    Mid-continent                         6       4      10       9       3      12      23      41      64
    North Dakota                          0       1       1       0       0       0       1      17      18
    Wyoming                               2       0       2       2       0       2      12      20      32
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
    Subtotal Northern Division            8       5      13      11       3      14      36      78     114
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
    Subtotal Active Fleet                47      16      63      53       6      59     150     130     280
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
    Stacked Inventory                     7      15      22       4       3       7      20      82     102
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
    Subtotal U.S. Lower 48               54      31      85      57       9      66     170     212     382
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
TOTAL U.S. LAND DRILLING FLEET           55      31      86      67       9      76     186     215     401
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
CANADA                                    7       0       7       5       0       5      27      54      81
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
INTERNATIONAL

   Latin America

    Argentina                             0       0       0       0       0       0       3      12      15
    Bolivia                               1       0       1       0       0       0       1       2       3
    Colombia                              3       0       3       3       0       3       6       4      10
    Ecuador                               0       1       1       1       0       1       1       8       9
    Venezuela                             0       0       0       0       0       0       1       1       2
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
    Subtotal Latin America                4       1       5       4       0       4      12      27      39
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
   Australia and Far East
    Australia                             0       0       0       0       0       0       0       4       4
    Indonesia                             0       0       0       0       0       0       0       2       2
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
    Subtotal Australia and Far East       0       0       0       0       0       0       0       6       6
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
   Middle East/Africa/CIS
    Algeria                               2       0       2       3       0       3       5       0       5
    Kazakhstan                            1       0       1       1       0       1       3       2       5
    Oman                                  0       0       0       0       0       0       2       0       2
    Saudi Arabia                          2       0       2       5       0       5       7       0       7
    U.A.E                                 1       0       1       0       0       0       1       4       5
    Yemen                                 2       0       2       0       0       0       3       4       7
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
    Subtotal Middle East/Africa/CIS       8       0       8       9       0       9      21      10      31
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
Joint Venture
   Saudi Arabia                           4       0       4       1       0       1       5      11      16
   Oman                                   0       0       0       0       0       0       1       0       1
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
    Subtotal Joint Ventures               4       0       4       1       0       1       6      11      17
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
TOTAL INTERNATIONAL                      16       1      17      14       0      14      39      54      93
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
TOTAL GLOBAL LAND DRILLING FLEET         78      32     110      86       9      95     252     323     575
                                      -----   -----   -----   -----   -----   -----   -----   -----   -----
</Table>
<PAGE>
        Figure 4                 U.S. Land Drilling


                                     ALASKA

Nabors Alaska experienced a very good year in 2003, driven primarily by
developmental drilling activity on the North Slope where four rigs were active
the entire year. Multiple remote exploration projects early in the year also
contributed significantly. Rig 273, a large upgraded rig relocated from Wyoming,
was also busy for most of the year drilling two extended reach prospects in the
Cook Inlet.

The outlook for 2004 is expected to be down significantly with continued
contributions from the North Slope rigs diminished by the 2003 completion of two
long-term contracts - Rig 429 on the Osprey platform and Rig 33E on North Star
Island. Rig 14E, Nabors' Hercules airplane transportable rig, will conclude its
current contract in April and awaits future drilling projects that require this
unique style of rig. Several rigs from this unit are candidates for prospective
drilling projects in Russia.

An incremental contribution is expected from Rig 27E, drilling a high profile
exploratory well in the Beaufort Sea which, if successful, could lead to an
extended developmental drilling program. Relatively active winter exploration
activities coupled with the recent decision to go forward with plans to develop
a heavy oil reservoir near Kaparak should also contribute to results.

                          U.S. LOWER 48 LAND DRILLING

Results from our U.S. Lower 48 Land Drilling unit improved substantially
throughout the year with the number of active rigs climbing from 105 to 175, a
reflection of increased market share.

The year was highlighted by the refurbishment of two idle 1,500-horsepower rigs,
transforming them into uniquely designed skidded rigs for drilling closely
spaced wells on compact sites. Borrowing from North Slope experience, these rigs
are able to skid between wells on the same pad in a matter of hours, as opposed
to days when moving conventionally. Customer response has been excellent, even
more so given the small footprint and minimal environmental impact that
characterize these rigs, and subsequent refurbishments are likely for deployment
in this particularly active area of the country.

The uptick in activity that characterized the year required that Nabors
re-activate a substantial number of rigs that had been idle since 2001, although
most required little or no refurbishment before being put to work. Nabors
Drilling USA also continued upgrading selected elements of its fleet, the most
significant component of which is the addition of higher mud pump capacities and
the attendant power systems that facilitate the application of new technology.
This unit also completed the fleet-wide rollout of advanced instrumentation
systems and began the implementation of the OptiDrill(TM) automatic driller in
preparation for broader application.


                                  nbr {38-39}
<PAGE>


Nabors continued to focus on safety in 2003 with a significant improvement in
what is already the industry's best safety record, a notable accomplishment
considering the thousands of frequently inexperienced rig hands added during the
year. This is a reflection of the depth and effectiveness of Nabors' ongoing
safety program, which has seen the number of recordable incidents drop
precipitously over the last several years.

Going forward, Nabors plans to continue its focus on improving efficiency and
productivity, particularly in the area of rig moving time. As the drilling time
of wells continues to shorten with improvements in rig efficiency, the time
involved in moving is of increasing importance. Nabors continues to refine its
performance through better planning and the consolidation of rig components into
fewer loads, the latter designed to reduce the volume of labor-intensive work.

Customer indications regarding rig activity lead us to believe that we will see
steady improvement during the first half of the year with a likely significant
increase in rig activity in the second half. This should lead to increased
market share for Nabors, especially in the more complex directional and
horizontal wells where the need for higher specification, technically advanced
rigs fits our asset base. The magnitude of this increase in activity should
absorb much of the remaining capacity of quality rigs and bring the rig
supply/demand balance closer to the point where prices improve significantly.

                                     Canada

The effect of our prior year acquisitions combined with a steadily improving
market fueled a record year for Nabors Canada in 2003.

A number of other factors also contributed to this unit's strong performance,
notably higher average North American natural gas prices and a diminishing
differential between realized Canadian gas prices and U.S. gas prices. All of
this resulted in higher operating cash flows for our Canadian customers and the
corresponding improved access to capital markets.

The consolidation of mergers and acquisitions that occurred between two major
Canadian operators in 2002 was completed during the year. This resulted in the
restoration of drilling programs for the principals, as well as for smaller
independents who were able to acquire or lease those non-strategic properties
that were divested in the wake of the merger. Drilling activity was further
stimulated by government investment in infrastructure that increased access to
prospective oil and gas drilling properties, particularly in British Columbia,
and by the further streamlining of the stringent Canadian regulatory process.


<PAGE>



The improving market created opportunities for this unit to continue to invest
in its innovative new rig technology, building two new AC drive rigs. These new
designs, which can move in greatly reduced times, as much as 60 percent on
infield moves, were widely accepted by customers and were quickly committed to
long-term contracts at favorable terms.

The outlook for this unit in 2004 is excellent with early first quarter
performance surpassing last year's results for the same time period. The
company's plan to build more of our innovative fast moving AC rigs will also
enhance results as the year progresses. Nabors' performance should be bolstered
by a reduction in the seasonality of work in this market as operators better
allocate and prioritize resources between summer and winter drilling programs.

                                 International

Nabors Drilling International's performance was up substantially during the year
on the strength of nine incremental offshore rigs on long-term contracts.
Results were further bolstered by higher utilization of our land fleet,
particularly in the Middle East where all of our workable rigs were under
contract.

The most significant of these projects was the refurbishment, modification and
deployment of five under utilized workover platform rigs from the U.S. Gulf of
Mexico, where they had been assigned to Nabors Offshore, to Mexico's offshore
waters under Nabors Drilling International. Four of Nabors' idle offshore supply
vessels were also deployed to Mexico in support of these rigs. This also
broadened the market for Canrig top drives and Epoch instrumentation systems.

This unit was also successful in securing other platform projects using idle
capacity. These include contracts for a workover platform rig in India and a
2,000-horsepower MASE rig in Indonesia. We also secured a contract for a newly
acquired and refurbished jack-up rig in Trinidad and extended the contract of
another jack-up in Qatar. The Indian rig was particularly strategic in that it
replaced a competitive jack-up, delivering a significant improvement in
economics for our customer and laying the groundwork for other incremental rigs
in this area.

A full year's contribution from these rigs, increased bidding activity and the
emergence of other strategic projects hold promise that this unit will deliver a
significant increase in performance in 2004.

In Algeria, three of the five rigs deployed there are under contract and the
remaining two should resume work in the second quarter, with the possibility of
adding incremental rigs as activity in that country heats up.



                                  nbr {40-41}

<PAGE>


In Yemen, Rig One is expected to return to work in the third quarter after being
stacked at the end of 2003. Five other rigs will contribute the entire year and
prospects are good for an incremental rig in the third quarter.

The only soft spot in the forecast is in Latin and South America, where activity
is not expected to return to previous levels for some time. However, Nabors is
well positioned there when the inevitable upturn occurs.

                                 U.S. Offshore

Results for Nabors Offshore were relatively flat in 2003, but a meaningful
uptick in the fourth quarter, driven primarily by increased jack-up and workover
rig activity, appears to be sustainable throughout 2004. As the year drew to a
close, nearly all of this unit's 1,000-horsepower and larger platform rigs were
working and the pricing environment had substantially improved.

Nabors Offshore continued to emphasize safety during the year and the result was
the unit's best performance in the last three years. New training programs,
leadership meetings and pre-employment screenings combined to drop total
recordables from five in 2000 to 2.47 in 2003.

Going forward, this unit expects 2004 results to significantly exceed those of
2003, primarily on the strength of its ability to capture a disproportionate
share of the deep water market with its innovative MODS class rigs. The newest
of these, the MODS 150, was completed and began operations in January and the
MODS 140 was recently upgraded and commenced a one-year contract. The Nabors
fleet of MODS rigs now numbers six, with five working and one undergoing
refurbishment, and will expand to seven in June and eight in August with the
completion and deployment of MODS 200 and 201, respectively. The latter two rigs
incorporate AC drive technology and programmable logic controllers which
facilitate the utilization of the latest drilling technologies and enhance
overall efficiency and safety.

Further bolstering this unit is the continuing high utilization of our
1,000-horsepower and larger self-erecting platform rigs, which has been helped
by last year's export of several rigs in this class to international venues for
long-term contracts. In February, our recently upgraded barge drilling rig
(BR-300) should recommence operations with greatly enhanced drilling capacity
and a reduced minimum draft. This is now the most versatile rig for the deep
horizon prospects of the shallowest water areas of the Gulf of Mexico. It also
appears likely that we will see a continuance of the improving market for our
platform and jack-up workover rigs that materialized late last year.

<PAGE>
                            U.S. Land Well-Servicing

Results for Pool Well Services were up substantially in 2003, primarily
attributable to an increase in activity for our higher margin 24-hour rigs
involved in workover, completion and gas well stimulation operations.

Pool's continuing focus on safety and training again paid dividends in 2003 as
this unit's recordable incident rate dropped from 2.5 to 2.16. The company once
again achieved the industry's best safety performance, receiving the Gold Safety
Award by the Association of Energy Service Companies for the seventh year in a
row.

Pool continued its upgrade and refurbishment program, reactivating long idled
rigs at less than half the cost of a new build in response to increased market
demand. Pool also completed the purchase of its first new generation
electronically-controlled workover rig, developed in conjunction with National
Oilwell. The rig has several features that provide greater efficiency and
safety, some of which will be exclusive to Pool, and will undergo an extensive
test period to fully evaluate the expected value for our customers and the
return on investment for Pool.

Going forward, Pool is implementing a new generation of instrumentation for well
service rigs in conjunction with sister company Epoch Well Services. Designed to
enhance safety and operational efficiency, this new instrumentation will provide
detection and early warning of impending problems. The first ten installations
will serve as a test group, with a broader rollout planned for the third
quarter.

                            Other Operating Segments

                             MARINE TRANSPORTATION

This unit experienced a down year in 2003, weathering a significantly reduced
level of activity in the U.S. Gulf of Mexico. Fleet utilization remained high
during the year, but pricing declined in the face of an over supply of available
equipment.

Safety continued to be a high priority in 2003 as additional training served to
improve upon an already excellent record. Our operating clients incurred only
one lost time accident in the last 1.2 million man hours, continuing to be among
the industry's best.


                                  nbr {42-43}

<PAGE>


Prospects for 2004 continue to be marginal as new capacity construction by
competitors continues. We are coping with this situation by exporting vessels to
various international venues such as Mexico where we reflagged four units to
support Nabors offshore rigs. Upgrades to the dynamic positioning systems of our
Super 200 class vessels are also serving to maintain the desirability of these
units in the market.

                        CANRIG DRILLING TECHNOLOGY, LTD.

Canrig's performance in 2003 was up slightly over the previous year, primarily
on the strength of a substantial improvement in third-party sales. Nearly 70
percent of this unit's top drive shipments were to non-Nabors customers, up from
only 30 percent just two years ago.

The successful introduction of a 175-ton AC top drive was a
highlight of the year and gives Canrig a complete range of top drives. Five were
delivered during the year with six more scheduled for delivery in 2004. The
company also introduced remote diagnostics, a service which will allow
technicians to troubleshoot top drive problems worldwide from base facilities in
Houston.

Going forward, Canrig expects its results to continue to be positively impacted
by expanding third-party sales and the delivery of the six 175-ton units.
Sustaining improvement in profitability is more likely as top drive parts sales
and 1,000-hour recertifications are an increasingly significant contributor. The
company will continue to design and implement new and innovative products like
remote diagnostics, and seek to acquire products and services that will add
content and value for our customers.

Canrig will begin licensing a soft torque application for its top drives in
2004. This feature will be optional on Canrig top drives, but its ability to
extend drill string and bit life and deliver faster rates of penetration should
improve market acceptance of this product on both new models and retrofits.

                           EPOCH WELL SERVICES, INC.

Results were flat in 2003, but this unit took several actions that will be
strategic in the coming year. Epoch completed the rollout of a significantly
enhanced version of its Rigwatch rig instrumentation product that incorporates
the best features of the Ryan Energy Technologies instrumentation system. This
unit also upgraded its satellite data transmission capabilities with new
components and a new software platform for real-time data transmission through
mywells.com, the company's internet data transmission product.

Going forward, this unit expects to roll out the OptiDrill(TM) automatic
drilling system that was developed by Noble Corporation, licensed and jointly
marketed by Nabors. Field testing on ten Nabors drilling rigs have validated our
expectations that this product provides superior rates of penetration and the
corresponding improvement in drilling performance. Epoch is accelerating the
implementation of this product on a broad range of Nabors rigs in 2004,
improving their marketability.


<PAGE>


Epoch has begun implementation of a new generation of instrumentation for well
service rigs in conjunction with sister company Pool Well Services. Designed to
enhance safety and operational efficiency, this new instrumentation will provide
detection and early warning of potential problems. The first ten installations
will serve as a test group, with a broader rollout planned for the third
quarter.

Epoch will also introduce a remote mud logging service during the year. It
utilizes satellite technology to provide a higher level of service at lower
costs for our customers.

                            RYAN ENERGY TECHNOLOGIES

Results were down slightly in 2003 as this unit integrated their rig
instrumentation product into Epoch's Rigwatch and completed their transition
into the Nabors organization.

Going forward, Ryan expects 2004 results to improve as both U.S. and Canadian
operations start the year strong, with improved utilization tracking increased
drilling activity, and a cost reduction effort takes effect. This unit will
continue to focus on development of technology that will broaden its
participation in the under-balanced drilling market, and continue to look for
opportunities to package its products and services with those offered by other
Nabors companies.

                             PEAK OILFIELD SERVICES

Results for Peak Oilfield Services, our Alaskan construction and logistics joint
venture, were down slightly in 2003 as a very strong year in support of
exploration was offset by the loss of a major North Slope contract. Peak
mitigated the loss of the contract by immediately instituting a reorganization
and cost-reduction plan.

More than 50 miles of ice roads and two ice islands were constructed during the
year, the latter two for a new customer drilling in the Beaufort Sea. Peak's
Kenai operation was also up substantially in support of offshore drilling
activity.

Going forward, this unit's performance should be up slightly in 2004 on the
strength of increased exploration activity on the North Slope and additional
developmental drilling in Prudhoe Bay and Kuparuk, both already evident in
January and February. Drilling support in Kenai should also be up and the
company will continue its aggressive approach to improving its safety
performance.

                                  nbr {44-45}
<PAGE>

                           FINANCIAL REVIEW

                           46  Selected Financial Data

                           48  Management's Discussion and Analysis
                               of Financial Condition and Results of Operations

                           68  Report of Independent Auditors

                           69  Consolidated Balance Sheets

                           70  Consolidated Statements of Income

                           71  Consolidated Statements of Cash Flows

                           72  Consolidated Statements of Changes in
                               Shareholders' Equity

                           75  Notes to Consolidated Financial Statements



<PAGE>
                              SELECTED FINANCIAL DATA
                    (NABORS INDUSTRIES LTD. AND SUBSIDIARIES)

<Table>
<Caption>
OPERATING DATA(1)(2)                                     YEAR ENDED DECEMBER 31,
-----------------------     -----------------------------------------------------------------------------
<S>                         <C>           <C>          <C>          <C>          <C>          <C>
(IN THOUSANDS,                 2003          2002         2001         2000         1999         1998
EXCEPT PER SHARE
AMOUNTS AND RATIO
DATA)

Revenues and other
  income:

  Operating revenues        $ 1,880,003   $ 1,466,443  $ 2,201,736  $ 1,388,660  $   666,429  $ 1,008,169

  Earnings (losses)
    from unconsolidated
    affiliates                   10,183        14,775       26,334       26,283        3,757         (305)

  Interest income                27,752        34,086       53,973       20,581        8,756        1,480

  Other income, net               4,908         3,708       28,650       27,157        8,860       31,626
                            -----------   -----------  -----------  -----------  -----------  -----------
  Total revenues and
    other income              1,922,846     1,519,012    2,310,693    1,462,681      687,802    1,040,970
                            -----------   -----------  -----------  -----------  -----------  -----------
Costs and other
  deductions:

  Direct costs                1,276,953       973,910    1,366,967      938,651      446,597      663,551

  General and
    administrative
    expenses                    165,403       141,895      135,496      106,504       65,288       77,026

  Depreciation and
    amortization                226,528       187,665      184,119      148,087       98,152       84,949

  Depletion                       8,599         7,700        5,777        4,326        1,741           --

  Interest expense               70,740        67,068       60,722       35,370       30,395       15,463
                            -----------   -----------  -----------  -----------  -----------  -----------
Total costs and
  other deductions            1,748,223     1,378,238    1,753,081    1,232,938      642,173      840,989
                            -----------   -----------  -----------  -----------  -----------  -----------
Income before
  income taxes                  174,623       140,774      557,612      229,743       45,629      199,981

Income tax (benefit)
  expense                       (17,605)       19,285      200,162       92,387       17,925       74,993
                            -----------   -----------  -----------  -----------  -----------  -----------
Net income                  $   192,228   $   121,489  $   357,450  $   137,356  $    27,704  $   124,988
                            -----------   -----------  -----------  -----------  -----------  -----------
Earnings per
  diluted share             $      1.25   $       .81  $      2.24  $       .90  $       .23  $      1.16

Weighted-average
  number of diluted
  common shares
  outstanding                   156,897       149,997      168,790      152,417      120,449      112,555

Capital expenditures
  and acquisitions
  of businesses(4)          $   357,393   $   702,843  $   803,241  $   334,279  $   837,732  $   315,057

Interest coverage ratio(5)        6.8:1         6.0:1       13.3:1       11.8:1        5.8:1       19.4:1
                            -----------   -----------  -----------  -----------  -----------  -----------
</Table>

<Table>
<Caption>
                                TWELVE       THREE
                              MONTHS ENDED   MONTHS
                              DECEMBER 31,   ENDED
OPERATING DATA(1)(2)          (UNAUDITED)  DECEMBER 31,         YEAR ENDED SEPTEMBER 30,
-----------------------       -----------  -----------   -------------------------------------
<S>                           <C>          <C>           <C>          <C>          <C>
(IN THOUSANDS,                  1997(3)       1997           1997         1996        1995
EXCEPT PER SHARE
AMOUNTS AND RATIO
DATA)

Revenues and other
  income:

  Operating revenues          $ 1,114,758  $   302,831   $ 1,028,853  $   719,604  $   572,788

  Earnings (losses)
    from unconsolidated
    affiliates                        274          (25)          450          139           --

  Interest income                   1,936           93         3,422        2,695        1,694

  Other income, net                28,502        2,303        40,747       13,690        5,990
                              -----------  -----------   -----------  -----------  -----------
  Total revenues and
    other income                1,145,470      305,202     1,073,472      736,128      580,472
                              -----------  -----------   -----------  -----------  -----------
Costs and other
  deductions:

  Direct costs                    774,856      199,714       737,780      539,665      434,097

  General and
    administrative
    expenses                       72,478       18,580        70,371       56,862       49,094

  Depreciation and
    amortization                   72,350       20,313        66,391       46,117       31,042

  Depletion                            --           --            --           --           --

  Interest expense                 16,323        3,979        16,520       11,884        7,611
                              -----------  -----------   -----------  -----------  -----------
Total costs and
  other deductions                936,007      242,586       891,062      654,528      521,844
                              -----------  -----------   -----------  -----------  -----------
Income before
  income taxes                    209,463       62,616       182,410       81,600       58,628

Income tax (benefit)
  expense                          73,443       21,289        67,602       11,100        7,524
                              -----------  -----------   -----------  -----------  -----------
Net income                    $   136,020  $    41,327   $   114,808  $    70,500  $    51,104
                              -----------  -----------   -----------  -----------  -----------
Earnings per
  diluted share               $      1.24  $       .37   $      1.08  $       .75  $       .57

Weighted-average
  number of diluted
  common shares
  outstanding                     113,793      116,427       111,975       93,752       89,655

Capital expenditures
  and acquisitions
  of businesses(4)            $   381,196  $    83,814   $   399,895  $   177,925  $   144,560

Interest coverage ratio(5)         18.3:1       21.8:1        16.1:1       11.7:1       12.8:1
                              -----------  -----------   -----------  -----------  -----------
</Table>

<PAGE>

<Table>
<Caption>


BALANCE SHEET DATA(1)(2)                                      AS OF DECEMBER 31,
-----------------------------  ----------------------------------------------------------------------------
<S>                            <C>          <C>          <C>          <C>          <C>          <C>
(IN THOUSANDS, EXCEPT
  RATIO DATA)                     2003         2002          2001          2000          1999        1998

Cash and cash equivalents,
  and short-term and long-term
  marketable securities        $ 1,532,090  $ 1,330,799  $   918,637  $   550,953  $   111,666  $    47,340

Working capital                    917,274      618,454      700,816      524,437      195,817       36,822

Property, plant and
 equipment, net                  2,990,792    2,801,067    2,451,386    1,835,039    1,678,664    1,127,154

Total assets                     5,602,692    5,063,872    4,151,915    3,136,868    2,398,003    1,465,907
Long-term debt                   1,985,553    1,614,656    1,567,616      854,777      482,600      217,034
Shareholders' equity           $ 2,490,275  $ 2,158,455  $ 1,857,866  $ 1,806,468  $ 1,470,074  $   867,469
Funded debt to capital ratio:
  Gross(6)                          0.48:1       0.49:1       0.46:1       0.32:1       0.25:1       0.26:1
  Net(7)                            0.23:1       0.26:1       0.26:1       0.15:1       0.20:1       0.17:1
</Table>


<Table>
<Caption>
                                   AS OF
                                 DECEMBER 31,
BALANCE SHEET DATA(1)(2)         (UNAUDITED)          AS OF SEPTEMBER 30,
-----------------------------    ------------  -------------------------------------
<S>                              <C>           <C>          <C>          <C>
(IN THOUSANDS, EXCEPT
  RATIO DATA)                          1997        1997       1996      1995

Cash and cash equivalents,
  and short-term and long-term
  marketable securities          $    42,135   $    53,323  $   115,866  $    24,979

Working capital                       62,571        70,872      172,091       33,892

Property, plant and
 equipment, net                      923,402       861,393      511,203      393,464

Total assets                       1,281,306     1,234,232      871,274      593,272
Long-term debt                       226,299       229,507      229,504       51,478
Shareholders' equity             $   767,340   $   727,843  $   457,822  $   368,750
Funded debt to capital ratio:
  Gross(6)                            0.27:1        0.27:1       0.35:1       0.20:1
  Net(7)                              0.20:1        0.20:1       0.21:1       0.09:1
</Table>

(1)  Our acquisitions' results of operations and financial position have been
     included beginning on the respective dates of acquisition and include Ryan
     Energy Technologies, Inc. (October 2002), Enserco Energy Service Company
     Inc. (April 2002), Command Drilling Corporation (November 2001), Pool
     Energy Services Co. (November 1999), Bayard Drilling Technologies, Inc.
     (April 1999), New Prospect Drilling Company (May 1998), Can-Tex Drilling &
     Exploration, Ltd. land rigs (May 1998), Veco Drilling, Inc. land rigs
     (November 1997), Diamond L Drilling & Production land rigs (November 1997),
     Cleveland Drilling Company, Inc. (August 1997), Chesley Pruet Drilling
     Company (April 1997), Adcor-Nicklos Drilling Company (January 1997,
     retroactive to October 1996), Noble Drilling Corporation land rigs
     (December 1996), Exeter Drilling Company and its subsidiary, J.W. Gibson
     Well Services Company (April 1996), and Delta Drilling Company (January
     1995). The results of operations also reflect the disposition of our UK
     North Sea (November 1996) and J.W. Gibson (January 1998) operations.

(2)  We changed our fiscal year end from September 30 to December 31, effective
     for the fiscal year beginning January 1, 1998. The three-month transition
     period from October 1, 1997 through December 31, 1997 preceded the start of
     the new fiscal year.

(3)  Represents unaudited recast financial data for the twelve months ended
     December 31, 1997. This data was derived by adjusting the audited results
     for the year ended September 30, 1997 to exclude the unaudited results for
     the quarter ended December 31, 1996 and to include the audited results for
     the three months ended December 31, 1997.

(4)  Represents capital expenditures and the portion of the purchase price of
     acquisitions allocated to fixed assets and goodwill based on their fair
     market value.

(5)  The interest coverage ratio is computed by calculating the sum of income
     before income taxes, interest expense, depreciation and amortization, and
     depletion expense and then dividing by interest expense. This ratio is a
     method for calculating the amount of cash flows available to cover interest
     expense.

(6)  The gross funded debt to capital ratio is calculated by dividing funded
     debt by funded debt plus capital. Funded debt is defined as the sum of (1)
     short-term borrowings, (2) current portion of long-term debt and (3)
     long-term debt. Capital is defined as shareholders' equity.

(7)  The net funded debt to capital ratio is calculated by dividing net funded
     debt by net funded debt plus capital. Net funded debt is defined as the sum
     of (1) short-term borrowings, (2) current portion of long-term debt and (3)
     long-term debt and then subtracting cash and cash equivalents and
     marketable securities. Capital is defined as shareholders' equity.


                                   nbr (46-47)
<PAGE>

                    MANAGEMENT'S DISCUSSION AND ANALYSIS OF
                 FINANCIAL CONDITION AND RESULTS OF OPERATIONS

                   {NABORS INDUSTRIES LTD. AND SUBSIDIARIES}

Nature of Operations

     Nabors is the largest land drilling contractor in the world, with almost
600 land drilling rigs. We conduct oil, gas and geothermal land drilling
operations in the U.S. Lower 48 states, Alaska, Canada, South and Central
America, the Middle East, the Far East and Africa. Nabors also is one of the
largest land well-servicing and workover contractors in the United States and
Canada. We own approximately 750 land workover and well-servicing rigs in the
United States, primarily in the southwestern and western United States, and
approximately 200 land workover and well-servicing rigs in Canada. Nabors is a
leading provider of offshore platform workover and drilling rigs, and owns 45
platform, 16 jack-up and three barge rigs in the Gulf of Mexico and
international markets. These rigs provide well-servicing, workover and drilling
services. We also have a 50% ownership interest in a joint venture in Saudi
Arabia, which owns 17 rigs.

     To further supplement and complement our primary business, we offer a wide
range of ancillary wellsite services, including engineering, transportation,
construction, maintenance, well logging, directional drilling, rig
instrumentation, data collection and other support services, in selected
domestic and international markets. Our land transportation and hauling fleet
includes approximately 240 rig and oilfield equipment hauling tractor-trailers
and a number of cranes, loaders and light-duty vehicles. We maintain
approximately 300 fluid hauling trucks, approximately 800 fluid storage tanks,
ten saltwater disposal wells and other auxiliary equipment used in drilling,
workover and well-servicing operations in the United States. In addition, we
time charter a fleet of 31 marine transportation and supply vessels, which
provide transportation of drilling materials, supplies and crews for offshore
operations primarily in the Gulf of Mexico. We manufacture and lease or sell top
drives for a broad range of drilling applications, directional drilling systems,
rig instrumentation and data collection equipment and rig reporting software. We
have also made selective investments in oil and gas exploration, development and
production activities, most recently with El Paso Corporation.

     The majority of our business is conducted through our various Contract
Drilling operating segments, which include our drilling, workover and
well-servicing operations, on land and offshore. Our operating segments engaged
in marine transportation and supply services, drilling technology and top drive
manufacturing, directional drilling, rig instrumentation and software, and
construction and logistics operations are aggregated in a category labeled Other
Operating Segments for segment reporting purposes. Our limited oil and gas
exploration, development and production operations are included in a category
labeled Oil and Gas for segment reporting purposes. A discussion of our results
of operations for the last three years is included below. This discussion should
be read in conjunction with our accompanying consolidated financial statements
and notes thereto.

     This discussion includes various forward-looking statements about our
markets, demand for our products and services and our future results. These
statements are "forward-looking statements" within the meaning of the safe
harbor provisions of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities Act of 1934. These forward-looking statements are not
historical facts, but instead are based upon our analysis of currently available
competitive, financial and economic data and our operating plans. They are
inherently uncertain and investors should recognize that events and actual
results could turn out to be significantly different from our expectations.
Important factors, among others, that could cause our results to differ,
possibly materially, from those indicated in the forward-looking statements are
discussed below under Forward-Looking Statements.

     As used in this Report, "we," "us," "our" and "Nabors" means Nabors
Industries Ltd. and, where the context requires, includes our subsidiaries.


<PAGE>

RESULTS OF OPERATIONS

     The following tables set forth certain information with respect to our
reportable segments and rig activity:

<Table>
<Caption>
                                              YEAR ENDED DECEMBER 31,                     INCREASE (DECREASE)
                                     ---------------------------------------   -------------------------------------------
<S>                                  <C>           <C>           <C>           <C>            <C>    <C>             <C>
(IN THOUSANDS, EXCEPT
PERCENTAGES AND RIG ACTIVITY)            2003          2002          2001           2003 TO 2002           2002 TO 2001

Reportable segments:
 Operating revenues and Earnings
 from unconsolidated affiliates:
 Contract Drilling:(1)
    U.S. Lower 48 Land Drilling      $   476,258   $   374,659   $ 1,007,300   $   101,599     27%   $  (632,641)    (63%)
    U.S. Land Well-servicing             312,279       294,428       345,785        17,851      6%       (51,357)    (15%)
    U.S. Offshore                        101,566       105,717       226,078        (4,151)    (4%)     (120,361)    (53%)
    Alaska                               112,092       118,199       133,634        (6,107)    (5%)      (15,435)    (12%)
    Canada                               322,303       141,497        86,310       180,806    128%        55,187      64%
    International                        396,884       320,160       282,404        76,724     24%        37,756      13%
                                     -----------   -----------   -----------   -----------    ---    -----------     ---
      Subtotal Contract Drilling(2)    1,721,382     1,354,660     2,081,511       366,722     27%      (726,851)    (35%)
    Oil and Gas(3)                        16,919         7,223         5,529         9,696    134%         1,694      31%
    Other Operating Segments(4)(5)       201,660       174,775       259,298        26,885     15%       (84,523)    (33%)
    Other reconciling items(6)           (49,775)      (55,440)     (118,268)        5,665     10%        62,828      53%
                                     -----------   -----------   -----------   -----------    ---    -----------     ---
      Total                          $ 1,890,186   $ 1,481,218   $ 2,228,070   $   408,968     28%   $  (746,852)    (34%)
                                     -----------   -----------   -----------   -----------    ---    -----------     ---
Adjusted income (loss) derived from
 operating activities:(7)
 Contract Drilling:
    U.S. Lower 48 Land Drilling      $    16,800   $    23,415   $   286,856   $    (6,615)   (28%)  $  (263,441)    (92%)
    U.S. Land Well-servicing              47,082        38,631        64,446         8,451     22%       (25,815)    (40%)
    U.S. Offshore                          1,649        (1,397)       29,874         3,046    218%       (31,271)   (105%)
    Alaska                                37,847        31,387        30,445         6,460     21%           942       3%
    Canada                                59,856        17,413        30,971        42,443    244%       (13,558)    (44%)
    International                         77,964        76,121        58,549         1,843      2%        17,572      30%
                                     -----------   -----------   -----------   -----------    ---    -----------     ---
      Subtotal Contract Drilling         241,198       185,570       501,141        55,628     30%      (315,571)    (63%)
    Oil and Gas                            5,850        (1,058)         (737)        6,908    653%          (321)    (44%)
    Other Operating Segments               3,266        24,660        87,847       (21,394)   (87%)      (63,187)    (72%)
    Other reconciling items(8)           (37,611)      (39,124)      (52,540)        1,513      4%        13,416      26%
                                     -----------   -----------   -----------   -----------    ---    -----------     ---
Total adjusted income derived
 from operating activities           $   212,703   $   170,048   $   535,711   $    42,655     25%   $  (365,663)    (68%)
Interest expense                         (70,740)      (67,068)      (60,722)       (3,672)    (5%)       (6,346)    (10%)
Interest income                           27,752        34,086        53,973        (6,334)   (19%)      (19,887)    (37%)
Other income, net                          4,908         3,708        28,650         1,200     32%       (24,942)    (87%)
                                     -----------   -----------   -----------   -----------    ---    -----------     ---
Income before income taxes           $   174,623   $   140,774   $   557,612   $    33,849     24%   $  (416,838)    (75%)
                                     -----------   -----------   -----------   -----------    ---    -----------     ---
</Table>

                                   nbr {48-49}
<PAGE>
<Table>
<Caption>
                                           YEAR ENDED DECEMBER 31,                    INCREASE (DECREASE)
                                  ---------------------------------------   ---------------------------------------
<S>                               <C>           <C>           <C>            <C>                  <C>
(IN THOUSANDS, EXCEPT PERCENTAGES
AND RIG ACTIVITY)                     2003          2002          2001           2003 TO 2002         2002 TO 2001
Rig activity:
  Rig years:(9)
    U.S. Lower 48 Land Drilling         143.1         103.0         209.7          40.1    39%         (106.7)  (51%)
    U.S. Offshore                        14.1          14.5          28.8           (.4)   (3%)         (14.3)  (50%)
    Alaska                                7.9           9.3          10.9          (1.4)  (15%)          (1.6)  (15%)
    Canada                               42.1          22.9          20.4          19.2    84%            2.5    12%
    International(10)                    61.1          55.1          54.5           6.0    11%             .6     1%
                                  -----------   -----------   -----------   -----------   ---     -----------   ---
    Total rig years                     268.3         204.8         324.3          63.5    31%         (119.5)  (37%)
                                  -----------   -----------   -----------   -----------   ---     -----------   ---
Rig hours:(11)
    U.S. Land Well-servicing        1,088,511     1,014,657     1,170,104        73,854     7%       (155,447)  (13%)
    Canada Well-servicing(12)         321,472       164,785            --       156,687    95%        164,785    --
                                  -----------   -----------   -----------   -----------   ---     -----------   ---
    Total rig hours                 1,409,983     1,179,442     1,170,104       230,541    20%          9,338     1%
                                  -----------   -----------   -----------   -----------   ---     -----------   ---
</Table>

(1)  These segments include our drilling, workover and well-servicing
     operations, on land and offshore.

(2)  Includes Earnings from unconsolidated affiliates, accounted for by the
     equity method, of $2.8 million, $3.9 million and $9.0 million for the years
     ended December 31, 2003, 2002 and 2001, respectively.

(3)  Represents our oil and gas exploration, development and production
     operations.

(4)  Includes our marine transportation and supply services, drilling technology
     and top drive manufacturing, directional drilling, rig instrumentation and
     software, and construction and logistics operations.

(5)  Includes Earnings from unconsolidated affiliates, accounted for by the
     equity method, of $7.4 million, $10.9 million and $17.3 million for the
     years ended December 31, 2003, 2002 and 2001, respectively.

(6)  Represents the elimination of inter-segment transactions.

(7)  Adjusted income (loss) derived from operating activities is computed by:
     subtracting direct costs, general and administrative expenses, and
     depreciation and amortization, and depletion expense from Operating
     revenues and then adding Earnings from unconsolidated affiliates. Such
     amounts should not be used as a substitute to those amounts reported under
     accounting principles generally accepted in the United States of America
     (GAAP). However, management evaluates the performance of our business units
     and the consolidated company based on several criteria, including adjusted
     income (loss) derived from operating activities, because it believes that
     this financial measure is an accurate reflection of the ongoing
     profitability of our company. A reconciliation of this non-GAAP measure to
     income before income taxes, which is a GAAP measure, is provided within the
     table set forth immediately following the heading Results of Operations
     above.

(8)  Represents the elimination of inter-segment transactions and unallocated
     corporate expenses.

(9)  Excludes well-servicing rigs, which are measured in rig hours. Includes our
     equivalent percentage ownership of rigs owned by unconsolidated affiliates.
     Rig years represents a measure of the number of equivalent rigs operating
     during a given period. For example, one rig operating 182.5 days during a
     365-day period represents 0.5 rig years.

(10) International rig years include our equivalent percentage ownership of rigs
     owned by unconsolidated affiliates which totaled 3.8 years, 3.7 years and
     2.3 years during the years ended December 31, 2003, 2002 and 2001,
     respectively.

(11) Rig hours represents the number of hours that our well-servicing rig fleet
     operated during the year.

(12) The Canada Well-servicing operation was acquired during April 2002 as part
     of our acquisition of Enserco Energy Service Company Inc.


2003 COMPARED TO 2002

     Operating revenues and Earnings from unconsolidated affiliates for 2003
totaled $1.9 billion, representing an increase of $409.0 million, or 28%,
compared to 2002. Adjusted income derived from operating activities and net
income for 2003 totaled $212.7 million and $192.2 million ($1.25 per diluted
share), respectively, representing increases of 25% and 58%, respectively,
compared to 2002.

     The increase in our Operating revenues and Earnings from unconsolidated
affiliates during 2003 primarily resulted from higher revenues realized by our
Canadian, U.S. Lower 48 Land Drilling and International operations. The improved
revenues from our Canadian operations resulted from an increase in the level of
activity for our land drilling and well-servicing operations driven by increased
demand for our services in that market during 2003 and our acquisition of
Enserco Energy Service Company Inc. in April 2002. The Enserco acquisition
increased the number of drilling rigs owned and operated by Nabors in Canada by
30 drilling rigs while also adding over 200 well-servicing rigs. The improved
revenues for our U.S. Lower 48 Land Drilling operations resulted from higher
activity levels driven by a gradual increase in demand for drilling services in
that market during 2003. The overall increase in demand in these markets was
driven by higher average price levels for natural gas in 2003 compared to 2002.
International revenues improved primarily as a result of six new long-term
contracts for our operation in Mexico.

     The increase in adjusted income derived from operating activities during
2003 primarily resulted from the increase in revenues discussed above. However,
the overall increase in adjusted income derived from operating activities for
2003 was partially offset by lower average dayrates in our U.S. Lower 48 Land
Drilling operations during 2003 and lower margins realized by certain of our
Other Operating Segments.

<PAGE>
The decrease in average dayrates for our U.S. Lower 48 Land Drilling operations
resulted from dayrates declining during 2002 and remaining flat until the latter
part of 2003, when dayrates began to rise. The decline in dayrates during 2002
resulted from the weakness in this market over the period beginning in the third
quarter of 2001 and extending through the end of 2002. The decrease in margins
for our Other Operating Segments is discussed in detail below.

     Natural gas prices are the primary driver of our U.S. Lower 48 Land
Drilling, Canadian and U.S. Offshore (Gulf of Mexico) operations, while oil
prices are the primary driver of our Alaskan, International and U.S. Land
Well-servicing operations. The Henry Hub natural gas spot price (per Bloomberg)
averaged $5.49 per million cubic feet (mcf) during 2003, up from a $3.37 per mcf
average during 2002. West Texas intermediate spot oil prices (per Bloomberg)
averaged $31.06 per barrel during 2003, up from a $26.17 per barrel average
during 2002.

     Our operating results for 2004 are expected to increase from levels
realized during 2003 given our current expectations of commodity prices and the
related impact on drilling and well-servicing activity during 2004. The expected
increase in drilling activity is expected to have the largest impact on our
Canadian and U.S. Lower 48 Land Drilling operations. Canadian drilling activity
is subject to substantial levels of seasonality, as activity levels typically
peak in the first quarter, decline substantially in the second quarter, and then
generally increase over the last half of the year. As a result of our
acquisitions in Canada during 2001 and 2002, this seasonality has a more
significant impact on our overall results as our Canadian operations represent a
larger portion of our overall operations. We also expect an improvement in
operating results for our U.S. Offshore (Gulf of Mexico) operations during 2004
primarily as a result of incremental revenues from three new platform rigs for
deepwater development projects that we expect to commence operations during the
first half of 2004, as well as a recovery in the level of overall activity in
this market. We expect results from our International operations for 2004 to
increase slightly as a result of a full year of operations for contracts in
India and Indonesia, which began in the last half of 2003, and a full year of
operations in Mexico where rigs commenced operations over the first three
quarters of 2003. We also expect to see a number of rigs that had been operating
under long-term contracts for our International operations that were
unexpectedly idled in late 2003, return to work during 2004. Our U.S. Land
Well-servicing operations are expected to maintain a steady to slightly upward
trend for 2004 given our current expectations of commodity prices during 2004 as
discussed above. We expect results from our operations in Alaska to be reduced
overall during 2004 compared to 2003, as two of our rigs are nearing completion
on contracts that have not yet been renewed or replaced.

     CONTRACT DRILLING Our Contract Drilling operating segments contain one or
more of the following operations: drilling, workover and well-servicing, on land
and offshore. Operating revenues and Earnings from unconsolidated affiliates for
our Contract Drilling operating segments totaled $1.7 billion and adjusted
income derived from operating activities totaled $241.2 million in 2003,
representing increases of 27% and 30%, respectively, compared to 2002. Rig years
(excluding well-servicing rigs) increased to 268.3 years during 2003 from 204.8
years during 2002 as a result of increased capital spending by our customers,
which resulted from the improvement in commodity prices.

     U.S. Lower 48 Land Drilling Operating revenues and adjusted income derived
from operating activities totaled $476.3 million and $16.8 million,
respectively, in 2003, representing an increase of 27% and a decrease of 28%,
respectively, compared to 2002. The increase in Operating revenues resulted from
the increase in drilling activity driven by higher natural gas prices, which is
reflected in the increase in rig years to 143.1 years during 2003 compared to
103.0 years during 2002. Adjusted income derived from operating activities
decreased during 2003, despite the increase in rig activity, as a result of
lower average dayrates, rising labor costs and higher depreciation expense.

     U.S. Land Well-servicing Operating revenues and adjusted income derived
from operating activities totaled $312.3 million and $47.1 million,
respectively, in 2003, representing increases of 6% and 22%, respectively,
compared to 2002. The improved results in 2003 resulted from an increase in
well-servicing utilization driven by the increase in spending by our customers
during 2003 and a marginal increase in average dayrates compared to 2002. The
strengthening in this market resulted primarily from the improvement in
commodity prices in 2003. U.S. Land Well-servicing hours increased to 1,088,511
hours during 2003 from 1,014,657 hours during 2002.

     U.S. Offshore Operating revenues and adjusted income derived from operating
activities totaled $101.6 million and $1.6 million, respectively, in 2003,
representing a decrease of 4% and an increase of 218%, respectively, compared to
2002. The decrease


                                  nbr {50-51}
<PAGE>

in Operating revenues in 2003 primarily relates to the inclusion in our 2002
Operating revenues of $6.4 million of business interruption insurance proceeds
related to our Dolphin 105 jack-up rig, which was lost in a hurricane during
2002, and from lower rig years in 2003 compared to 2002. Rig years for our U.S.
Offshore operations totaled 14.1 years during 2003 compared to 14.5 years during
2002. The decrease in Operating revenues in 2003 was partially offset by higher
average dayrates in 2003 compared to 2002 resulting from an overall tightening
of rig supply in the U.S. Gulf of Mexico during 2003. The increase in adjusted
income derived from operating activities during 2003 resulted primarily from
increased working days for our 1,000-horsepower workover rigs that currently
generate higher daily cash margins than the remainder of our rigs, which was
only partially offset by lower rig years in 2003. Adjusted income derived from
operating activities for 2003 was also positively impacted by lower costs due to
increased monitoring of costs on working rigs and reductions in fixed overhead
and costs for non-working rigs.

     Alaskan Operating revenues and adjusted income derived from operating
activities totaled $112.1 million and $37.8 million, respectively, in 2003,
representing a decrease of 5% and an increase of 21%, respectively, compared to
2002. The decrease in Operating revenues resulted from lower drilling activity
reflected in the decrease in rig years to 7.9 years during 2003 from 9.3 years
during 2002, which was primarily driven by our customers decreasing their level
of winter exploration activity. This reduced activity level was partially offset
by an incremental $5.7 million of Operating revenues, representing business
interruption insurance proceeds recorded during 2003 related to the damage
incurred on one of our land drilling rigs in 2001, which exceeded the $3.1
million in business interruption insurance proceeds recorded during 2002 related
to another rig damaged in 2001. The increase in adjusted income derived from
operating activities resulted from the higher level of business interruption
insurance proceeds recognized in 2003 versus 2002 and from projects where we
earned a standby without crew rate, which adds to revenues at a level lower than
standard rates, but with minimal costs of operation.

     Canadian Operating revenues and adjusted income derived from operating
activities totaled $322.3 million and $59.9 million, respectively, in 2003,
representing increases of 128% and 244%, respectively, compared to 2002. These
increases reflect an increase in drilling and well-servicing revenues, which
resulted from an overall increase in Canadian drilling and well-servicing
activity driven by increased commodity prices, and from our acquisition of
Enserco in April 2002. Rig years in Canada increased to 42.1 years during 2003
from 22.9 years during 2002. Canadian Well-servicing hours totaled 321,472 hours
during 2003 compared to 164,785 hours during the period from April 26, 2002, the
date we acquired Enserco, through December 31, 2002.

     International Operating revenues and Earnings from unconsolidated
affiliates, and adjusted income derived from operating activities totaled $396.9
million and $78.0 million, respectively, in 2003, representing increases of 24%
and 2%, respectively, compared to 2002. The improved results in 2003 primarily
resulted from six new long-term contracts for our operation in Mexico.
International rig years increased to 61.1 years during the current year from
55.1 years during 2002 primarily as a result of these new contracts.

     OIL AND GAS This operating segment represents our investment in net profits
interests of oil and gas exploration, development and production operations. Oil
and Gas Operating revenues and adjusted income derived from operating activities
totaled $16.9 million and $5.9 million, respectively, in 2003, representing
increases of 134% and 653%, respectively, compared to 2002, resulting from the
agreements executed with El Paso Corporation in October 2003 discussed below.

     On October 8, 2003, we entered into two separate agreements with
wholly-owned subsidiaries of El Paso Corporation under which a subsidiary of
Nabors will contribute 20% of an estimated $400 million total cost to develop
approximately 110 wells in exchange for a 20% net profits interest in such wells
(cash proceeds available from production after royalties and operating costs
have been paid). The wells included in these agreements include a combination of
proved undeveloped, probable and possible reserves located primarily in South
Texas, North Louisiana and Offshore Gulf of Mexico. In the event that cash
proceeds totaling 117.5% of our total investment are received from the wells
subject to the applicable agreement, our net profits interest in those wells
will convert to an overriding royalty interest of 0.4% in the wells for the
remainder of the wells' productive lives. Either party may terminate the
agreements upon 30 days notice. El Paso will serve as operator of all the wells
covered in this development program.

     On November 6, 2003, we entered into two additional agreements with El Paso
to drill up to a total of 12 exploratory wells in South Texas and South
Louisiana. Through these agreements and a subsequent election under one of the
agreements, we have committed to contribute 25% of El Paso's share of the cost
of drilling and completing eight of the wells; 25% of El Paso's share of the
cost of drilling to casing point for three of the wells; and 20% of El Paso's
share of the cost of drilling to casing point for one of the wells. We are also
committed to contribute 12.5% of El Paso's share of any other costs of the
exploratory wells and of all costs of any development wells in which we elect to
participate on those prospects. In exchange, we receive a 12.5% interest in El
Paso's share in the prospect leases where the exploratory wells are drilled,
subject to certain penalty deductions in the event we elect to participate in
less than all development wells drilled. As of December 31, 2003, three wells
had commenced drilling under these agreements with one being declared a dry
hole, which resulted in a charge to direct costs of $1.4 million recorded during
the fourth quarter of 2003. The other two wells are in various stages of
completion, and an independent third party has concluded that those wells are
capable of production in paying quantities.

<PAGE>
     OTHER OPERATING SEGMENTS These operations include our marine transportation
and supply services, drilling technology and top drive manufacturing,
directional drilling, rig instrumentation and software, and construction and
logistics operations. Operating revenues and Earnings from unconsolidated
affiliates for our Other Operating Segments totaled $201.7 million during 2003
representing an increase of 15% compared to 2002. This increase primarily
resulted from the acquisition of Ryan Energy Technologies, Inc. during the
fourth quarter of 2002. Adjusted income derived from operating activities for
our Other Operating Segments totaled $3.3 million during 2003 representing a
decrease of 87% compared to 2002. While Ryan's results have been additive to our
revenues, this new business realized a loss during 2003. In addition, decreased
margins from our marine transportation services, which resulted from lower
average dayrates, and from our top drive manufacturing operations, which
resulted from fewer top drive sales in 2003 compared to 2002, resulted in lower
profitability for our Other Operating Segments compared to 2002.

     OTHER FINANCIAL INFORMATION General and administrative expenses increased
by $23.5 million, or 17%, in 2003 compared to 2002 primarily as a result of
increases related to our Canadian acquisitions in 2002 and increased
International activity. As a percentage of operating revenues, general and
administrative expenses decreased in 2003 compared to 2002 (8.8% vs. 9.7%) as
these expenses were spread over a larger revenue base.

     Depreciation and amortization, and depletion expense increased by $39.8
million, or 20%, in 2003 compared to 2002 as a result of an increase in average
rig years for our Canadian land drilling, U.S. Lower 48 Land Drilling and
International operations, a full year of depreciation in 2003 on assets acquired
in our Enserco (April 2002) and Ryan (October 2002) acquisitions, as well as
other capital expenditures during 2002 and 2003.

     Interest expense increased by $3.7 million, or 5%, in 2003 compared to 2002
resulting from the issuance of our $225 million aggregate principal amount of
4.875% senior notes and our $275 million aggregate principal amount of 5.375%
senior notes in August 2002, which was only partially offset by reduced interest
costs realized in 2003 from the issuance of our $700 million zero coupon senior
exchangeable notes in June 2003. Such notes will not accrue interest unless we
become obligated to pay contingent interest. The proceeds from this debt
issuance were used to redeem our $825 million zero coupon convertible senior
debentures, which had an effective interest rate of 2.5%. We also redeemed our
8.625% senior subordinated notes due April 2008 on April 1, 2003.

     Interest income decreased by $6.3 million, or 19%, in 2003 compared to
2002, reflecting lower average yields on investments resulting from the overall
declining interest rate environment, partially offset by higher average cash and
marketable securities balances.

     Other income increased by $1.2 million, or 32%, in 2003 compared to 2002.
Other income for 2003 includes net gains on marketable securities of
approximately $6.1 million and net gains on long-term assets of approximately
$2.5 million, partially offset by the recognition of approximately $1.2 million
of expense in 2003 related to the settlement of amounts due to the counterparty
for our range cap and floor derivative instrument, and a loss of approximately
$.9 million resulting from the redemption of our 8.625% senior subordinated
notes at prices higher than their carrying value on April 1, 2003. Other income
for 2002 includes net gains on marketable securities of approximately $2.9
million and net gains on long-term assets of approximately $4.6 million,
partially offset by mark-to-market losses recorded on our range cap and floor
derivative instrument of approximately $2.0 million and the recognition of
approximately $3.8 million in non-recurring corporate reorganization expense.

     Our effective income (benefit) tax rate was (10%) during 2003 compared to
14% during 2002. The tax benefit position for 2003 resulted primarily from tax
savings realized as a result of our corporate reorganization effective June 24,
2002. It is possible that the tax savings recorded as a result of the corporate
reorganization may not be realized, depending on the final disposition of
various legislative proposals introduced in the U.S. Congress, and any
responsive action taken by Nabors. We expect our effective income tax rate
during 2004 to be in the 10%-15% range because we expect a higher proportion of
our income to be generated in the U.S., which is generally taxed at a higher
rate than in international jurisdictions in which we operate.


                                   nbr {52-53}
<PAGE>

2002 COMPARED TO 2001

     Operating revenues and Earnings from unconsolidated affiliates in 2002
totaled $1.5 billion, representing a decrease of $746.9 million, or 34%,
compared to 2001. Adjusted income derived from operating activities and net
income in 2002 totaled $170.0 million and $121.5 million ($.81 per diluted
share), respectively, representing decreases of 68% and 66%, respectively,
compared to 2001.

     The decrease in our operating results in 2002 primarily resulted from the
continuing weak environment in several of our key North American markets. The
depressed price for natural gas and oil over the period beginning in the third
quarter of 2001 through the latter part of the first quarter of 2002 resulted in
decreased spending by our customers for our services during the second half of
2001 and for all of 2002.

     This decreased spending and corresponding decline in our rig activity
resulted in declining profitability for Nabors over that period. These lower
activity levels were experienced by a majority of our North American business
units, with the sharpest decline coming from our U.S. Lower 48 Land Drilling
business. The decrease in North American land and offshore drilling activity is
illustrated by the drilling industry's lower total active land and offshore rig
count. The drilling industry's average U.S. Land, Canadian Land and U.S.
Offshore rig counts during 2002 were lower by 29%, 23% and 26%, respectively,
than the 2001 period. Also contributing to the overall decline in our operating
results was a decline in activity for our U.S. Land Well-servicing and workover
business, driven primarily by lower rig utilization due to the overall weak
market, a decline in activity for our operations in Alaska, primarily resulting
from lower overall drilling activity in that market, and the loss of some higher
margin workover rigs and an offshore platform operation during the second half
of 2002.

     As discussed above, natural gas prices are the primary driver of our U.S.
Lower 48 Land Drilling, Canadian and U.S. Offshore (Gulf of Mexico) operations,
while oil prices are the primary driver of our Alaskan, International and U.S.
Land Well-servicing operations. The Henry Hub natural gas spot price (per
Bloomberg) averaged $3.37 per mcf during 2002, down from the $3.96 per mcf
average during 2001. West Texas intermediate spot oil prices (per Bloomberg)
averaged $26.17 per barrel during 2002, up slightly from $25.96 per barrel
during 2001. Beginning in the first quarter of 2002, a tightening in natural gas
and oil supply resulted in an improvement in natural gas and oil prices. Natural
gas and oil prices averaged $3.76 per mcf and $28.29 per barrel, respectively,
during the last six months of 2002, as compared to $2.98 per mcf and $24.01 per
barrel for the first six months of 2002. A substantial portion of the
improvement in natural gas prices occurred during the fourth quarter of 2002,
when natural gas prices averaged $4.31 per mcf. These price increases did not
result in a corresponding strengthening of our key North American markets until
early 2003.

     CONTRACT DRILLING Operating revenues and Earnings from unconsolidated
affiliates for our Contract Drilling operating segments totaled $1.4 billion and
adjusted income derived from operating activities totaled $185.6 million in
2002, representing decreases of 35% and 63%, respectively, compared to 2001. Rig
years (excluding well-servicing rigs) decreased to 204.8 years during 2002 from
an average of 324.3 years during 2001. The lower revenues realized by our U.S.
Lower 48 Land Drilling, U.S. Land Well-servicing, U.S. Offshore and Alaskan
business units during 2002 compared to 2001 were only partially offset by higher
revenues from our Canadian and International operations.

     U.S. Lower 48 Land Drilling Operating revenues and adjusted income derived
from operating activities totaled $374.7 million and $23.4 million,
respectively, representing decreases of 63% and 92%, respectively, compared to
2001. These substantial decreases were a result of decreased demand for our
drilling services. The weakness of the North American natural gas market during
2002 resulted in significant decreases in both rig years and dayrates. We began
to experience this deterioration in North American gas rig activity during the
third quarter of 2001 and such reduced rig activity continued through the end of
2002. U.S. Lower 48 Land Drilling rig years decreased to 103.0 years during 2002
from 209.7 years during 2001.

     U.S. Land Well-servicing Operating revenues and adjusted income derived
from operating activities totaled $294.4 million and $38.6 million,
respectively, in 2002, representing decreases of 15% and 40%, respectively,
compared to 2001. These decreases resulted from decreased activity as a function
of the reduction in capital spending by our customers resulting from lower oil
prices in the beginning of 2002 and, to a lesser extent, lower natural gas
prices over the same period. U.S. Land Well-servicing rig hours decreased to
1,014,657 hours during 2002 from 1,170,104 hours during 2001.

     U.S. Offshore Operating revenues and adjusted income (loss) derived from
operating activities totaled $105.7 million and ($1.4 million), respectively, in

<PAGE>

2002, representing decreases of 53% and 105%, respectively, compared to 2001.
These decreases resulted from lower rig years and lower average dayrates. This
negative trend began during the third quarter of 2001 and continued through the
second quarter of 2002, following the similar decline in natural gas and oil
prices over that period. During that period of time offshore operators reduced
their demand for offshore rigs and the prices they were willing to pay for
offshore services in the Gulf of Mexico. Offshore rig years decreased to 14.5
years during 2002 from 28.8 years during 2001. Our U.S. Offshore unit's 2002
operating results include an incremental $6.4 million, representing business
interruption insurance proceeds related to our Dolphin 105 jack-up rig, which
was lost in a hurricane during 2002. We also recorded a $2.3 million gain as a
result of a casualty insurance settlement in excess of the carrying value of
this rig, which is included in other income in our consolidated statement of
income for the year ended December 31, 2002.

     Alaskan Operating revenues and adjusted income derived from operating
activities totaled $118.2 million and $31.4 million, respectively, in 2002,
representing a decrease of 12% and an increase of 3%, respectively, compared to
2001. The decrease in Operating revenues resulted from lower drilling activity
reflected in the decrease in rig years to 9.3 years during 2002 from 10.9 years
during 2001. This reduced activity level was partially offset by an incremental
$3.1 million in Operating revenues, representing business interruption insurance
proceeds recorded during 2002 related to damage incurred on one of our land
drilling rigs in 2001, which resulted in the small increase in adjusted income
derived from operating activities in 2002 compared to 2001.

     Canadian Operating revenues and adjusted income derived from operating
activities totaled $141.5 million and $17.4 million, respectively, in 2002,
representing an increase of 64% and a decrease of 44%, respectively, compared to
2001. The increase in Operating revenues primarily resulted from an increase in
well-servicing revenues from our acquisition of Enserco in April 2002. Operating
revenues also increased due to a year-over-year increase in drilling revenues.
Drilling revenues increased due to our April 2002 acquisition of Enserco and our
November 2001 acquisition of Command Drilling Corporation. These acquisitions
increased our position in Canada with assets that are relatively new and in
excellent condition, allowing us to provide services to many of our key U.S.
customers who have increased their presence in Canada because of its
increasingly strategic importance to the North American gas supply market. Rig
years in Canada increased to 22.9 years during 2002 from 20.4 years during 2001.
Rig years peaked during the fourth quarter of 2002, averaging 29.6 years for the
period. Canadian well-servicing hours totaled 164,785 hours for the period from
April 26, 2002, the date we acquired Enserco, through December 31, 2002.
Adjusted income derived from operating activities for Canada decreased primarily
due to the addition of well-servicing operations in 2002 which tend to have
lower margins than drilling operations, lower average margins in our drilling
operations caused by the downward pressure on pricing for much of the first half
of 2002, as well as increased general and administrative expenses caused by our
Enserco and Command acquisitions and the related build-up of our Canadian
operations during 2002.

     International Operating revenues and Earnings from unconsolidated
affiliates, and adjusted income derived from operating activities totaled $320.2
million and $76.1 million, respectively, in 2002, representing increases of 13%
and 30%, respectively, compared to 2001. These increases resulted from higher
rig years and higher average dayrates in our Middle East operations, primarily
in Saudi Arabia and Yemen, and our African operations, primarily in Algeria.
International rig years increased slightly to 55.1 years during 2002 from 54.5
years during 2001.

     OIL AND GAS Operating revenues and adjusted loss derived from operating
activities for our Oil and Gas operating segment totaled $7.2 million and $1.1
million, respectively, in 2002, representing an increase of 31% and a decrease
of 44%, respectively, compared to 2001. The increase in Operating revenues
resulted from increased investment in selective oil and gas exploration,
development and production operations during 2002. We realized an adjusted loss
derived from operating activities in 2002 compared to adjusted income derived
from operating activities in 2001 as a result of increased depletion expense
driven by increased oil and gas production.

     OTHER OPERATING SEGMENTS Operating revenues and Earnings from
unconsolidated affiliates for our Other Operating Segments totaled $174.8
million in 2002, representing a decrease of 33% compared to 2001. Adjusted
income derived from operating activities totaled $24.7 million in 2002,
representing a 72% decrease compared to 2001. These decreases resulted primarily
from lower average dayrates and weak market conditions in our marine
transportation and supply services and U.S. trucking operations and from
decreased top drive sales.


                                   nbr {54-55}
<PAGE>

     OTHER FINANCIAL INFORMATION General and administrative expenses increased
by $6.4 million, or 5%, in 2002 compared to 2001 as a result of increases
related to our Canadian acquisitions partially offset by decreased rig activity.
As a percentage of operating revenues, general and administrative expenses
increased during 2002 compared to 2001 (9.7% vs. 6.2%) as these expenses were
spread over a lower revenue base.

     Depreciation and amortization, and depletion expense increased by $5.5
million, or 3%, in 2002 compared to 2001 as a result of significant capital
expenditures and acquisitions during 2001 and 2002. This was partially offset by
decreased rig activity, an extension of certain of our fixed asset depreciable
lives and the required discontinuance of goodwill amortization. Effective
October 1, 2001, we changed the depreciable lives of our drilling and workover
rigs from 4,200 to 4,900 active days, our jack-up rigs from 4,200 to 8,030
active days and certain other drilling equipment lives, to better reflect the
estimated useful lives of these assets. The effect of this change in accounting
estimate was accounted for on a prospective basis beginning October 1, 2001 and
decreased depreciation expense by $28.7 million and $8.6 million in 2002 and
2001, respectively. On January 1, 2002, we adopted Statement of Financial
Accounting Standards (SFAS) No. 142, "Goodwill and Other Intangible Assets,"
which resulted in us no longer amortizing goodwill. The effect of this change,
if applied to 2001, would have decreased amortization expense by approximately
$7.1 million for the year ended December 31, 2001.

     Interest expense increased in 2002 as a result of higher average
outstanding debt balances, resulting from the issuance of our $225 million
aggregate principal amount of 4.875% senior notes and $275 million aggregate
principal amount of 5.375% senior notes in August 2002, which added $8.3 million
to interest expense in 2002. Interest income decreased in 2002 due to lower
average yields on investments resulting from the overall declining interest rate
environment partially offset by higher average cash and marketable securities
balances.

     Other income decreased in 2002, compared to 2001, resulting primarily from
the following: a gain on extinguishment of debt of $15.3 million recorded in
2001, a year-to-year decrease in gains on long-term assets of $5.7 million and
corporate reorganization expense of $3.8 million recorded in 2002.

     Our effective income tax rate was 14% during 2002 compared to 36% during
2001 due primarily to an increase in international earnings as a percentage of
our overall earnings. Our international earnings, other than earnings from our
Canadian operations, generally are taxed at lower rates than earnings from our
U.S. operations. Our corporate reorganization also had the effect of lowering
our effective income tax rate. The tax benefit attributable to our corporate
reorganization in 2002 was approximately $13.0 million ($.09 per diluted share).
Excluding the $13.0 million in tax savings related to the corporate
reorganization, our effective tax rate for 2002 was 23%.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

     Our cash flows primarily depend on the level of spending by our primary
customers, oil and gas companies, for exploration, development and production
activities. Sustained increases or decreases in the price of natural gas or oil
could have a material impact on these activities, and could also materially
affect our cash flows. Certain uses of cash, such as the level of nonsustaining
capital expenditures, purchases and sales of marketable securities, issuances of
debt and repurchases of our common shares are within our control and are
adjusted as necessary based on market conditions. The following is a discussion
of our cash flows for the years ended December 31, 2003 and 2002.

     OPERATING ACTIVITIES Net cash provided by operating activities totaled
$395.8 million during 2003 compared to net cash provided by operating activities
totaling $400.9 million during 2002. During 2003 net income was increased for
non-cash items such as depreciation and amortization, and depletion, and was
reduced for changes in our working capital and other balance sheet accounts and
for our deferred income tax benefit. During 2002 net income was increased for
non-cash items such as depreciation and amortization, depletion, deferred income
taxes, and from changes in our working capital accounts.

     INVESTING ACTIVITIES Net cash used for investing activities totaled $408.3
million during 2003 compared to net cash used for investing activities totaling
$654.3 million during 2002. During 2003 cash was used for purchases, net of
sales, of marketable and non-marketable securities and capital expenditures.
During 2002 cash was used for our acquisitions of Ryan and Enserco, capital
expenditures, and for purchases, net of sales, of marketable and non-marketable
securities.

     FINANCING ACTIVITIES Net cash provided by financing activities totaled
$171.5 million during 2003 compared to net cash provided by financing activities
totaling $466.7 million during 2002. During 2003 cash was provided by
approximately $688.5 million in

<PAGE>

net proceeds from the issuance of our $700 million zero coupon senior
exchangeable notes on June 10, 2003 and was used for the reduction of long-term
debt of $544.5 million. Cash was also provided during the current year by our
receipt of proceeds totaling $26.3 million from the exercise of options and
warrants to acquire our common shares. During 2002 cash was provided by the
proceeds of $493.0 million from the issuance of senior notes in August 2002 and
by our receipt of proceeds totaling $12.9 million from the exercise of options
to acquire our common shares, and was used for the reduction of long-term debt
of $30.8 million.

     On June 10, 2003, we completed a private placement of $700 million
aggregate principal amount of zero coupon senior exchangeable notes due 2023.
The notes were reoffered by the initial purchaser of the notes to qualified
institutional buyers under Rule 144A of the Securities Act of 1933, as amended,
and outside the United States in accordance with Regulation S under the
Securities Act. The notes do not bear interest, do not accrete and have a zero
yield to maturity, unless we become obligated to pay contingent interest as
defined in the note indenture. See our discussion of additional provisions of
these notes in Note 8 to our accompanying consolidated financial statements.
Cash provided by issuance of the notes, net of issuance costs, totaled $688.5
million.

     We used a portion of the net proceeds from the issuance of the notes to
redeem the remaining outstanding principal amount of our $825 million zero
coupon convertible senior debentures due 2020 on June 20, 2003. The redemption
price was $655.50 per $1,000 principal amount of the debentures for an aggregate
redemption price paid of approximately $494.9 million. The remainder of the
proceeds of the notes were invested in cash and marketable securities and will
be used for general corporate purposes, including payments at the maturity of
our 6.8% senior notes due April 15, 2004.

     On April 1, 2003, we redeemed our 8.625% senior subordinated notes due
April 2008 and all associated guarantees at a redemption price of $1,043.13 per
$1,000 principal amount of the notes together with accrued and unpaid interest
to the date of redemption for an aggregate redemption price of $45.2 million.

FUTURE CASH REQUIREMENTS

     As of December 31, 2003, we had long-term debt, including current
maturities, of $2.3 billion and cash and cash equivalents and investments in
marketable securities of $1.5 billion. See table included under Fair Value of
Financial Instruments below for a breakout of the components of our long-term
debt as of December 31, 2003.

     Our 6.8% senior notes are due April 15, 2004 for an aggregate principal
amount of $295.3 million. This amount is classified in current liabilities in
our consolidated balance sheet as of December 31, 2003.

     Our $1.381 billion zero coupon convertible senior debentures due 2021 can
be put to us on February 5, 2006, February 5, 2011 and February 5, 2016, for a
purchase price equal to the issue price plus accrued original issue discount to
the date of repurchase. Our $700 million zero coupon senior exchangeable notes
due 2023 can be put to us on June 15, 2008, June 15, 2013 and June 15, 2018, for
a purchase price equal to 100% of the principal amount of the notes plus
contingent interest and additional amounts, if any. We may elect to pay all or a
portion of the purchase price of the debentures and the notes in common shares
instead of cash, depending upon our cash balances and cash requirements at that
time. We do not presently anticipate using common shares to satisfy any such
future purchase obligations. In accordance with the indenture with respect to
the debentures, we cannot redeem the $1.381 billion debentures before February
5, 2006. After that date, we may redeem all or a portion of the debentures for
cash at any time at their accreted value.

     As of December 31, 2003, we had outstanding capital expenditure purchase
commitments of approximately $26.1 million, primarily for rig-related enhancing
and sustaining capital expenditures. In addition, we estimate that we will
contribute approximately $57.1 million and $2.5 million in conjunction with our
agreements with El Paso Corporation during 2004 and 2005, respectively. In
addition to the purchase commitments discussed above, projected capital
expenditures for 2004 for sustaining and known new construction and enhancement
projects are expected to total approximately $340 million.

     We have historically completed a number of acquisitions and will continue
to evaluate opportunities to acquire assets or businesses to enhance our
operations. Several of our previous acquisitions were funded through issuances
of our common shares. Future acquisitions may be paid for using existing cash or
issuance of debt or Nabors shares. Such capital expenditures and acquisitions
will depend on our view of market conditions and other factors.


                                   nbr {56-57}
<PAGE>

     Historical capital expenditures and acquisitions of businesses, which
represent the portion of the purchase price of acquisitions allocated to fixed
assets and goodwill based on their fair market value, are classified as
follows:

<Table>
<Caption>
                           YEAR ENDED DECEMBER 31,
                   ------------------------------------
(IN THOUSANDS)        2003         2002          2001
                   ----------   ----------   ----------
<S>                <C>          <C>          <C>
Sustaining         $  159,932   $  102,633   $  231,683
Enhancement           110,852      136,837      398,513
Acquisitions           71,549      449,365      155,671
New Construction       15,060       14,008       17,374
                   ----------   ----------   ----------
                   $  357,393   $  702,843   $  803,241
                   ----------   ----------   ----------
</Table>

     The following table summarizes our contractual cash obligations as of
December 31, 2003:

<Table>
<Caption>
                                                          PAYMENTS DUE BY PERIOD
                                 -------------------------------------------------------------------------
(IN THOUSANDS)                      TOTAL       < 1 YEAR      1-3 YEARS        3-5 YEARS       THEREAFTER
                                 -----------   -----------   -----------      -----------      -----------
<S>                              <C>           <C>           <C>              <C>              <C>
Contractual cash
 obligations:
 Long-term debt:
   Principal                     $ 2,326,192   $   299,392   $   826,800(1)   $   700,000(2)   $   500,000
   Interest                          195,045        31,606        51,501           51,501           60,437
 Operating leases(3)                  24,804        10,096         9,883            2,561            2,264
 Capital expenditure
 purchase commitments(3)              85,786        83,224         2,562               --               --
 Time charter commitment(4)           92,626        27,056        53,964           11,606               --
 Employment contracts(3)               7,942         1,808         3,061            1,222            1,851
Pension funding
  obligations(5)                       1,490         1,490            --               --               --
                                 -----------   -----------   -----------      -----------      -----------
Total contractual cash
  obligations                    $ 2,733,885   $   454,672   $   947,771      $   766,890      $   564,552
                                 -----------   -----------   -----------      -----------      -----------
</Table>

----------

(1)  Represents our $1.381 billion zero coupon convertible senior debentures
     which can be put to us on February 5, 2006.

(2)  Represents our $700 million zero coupon exchangeable notes which can be put
     to us on June 15, 2008.

(3)  See Note 13 to the accompanying consolidated financial statements.

(4)  Relates to our future commitments under our time charter with Sea Mar
     Management LLC. See Related Party Transactions below.

(5)  See Note 11 to the accompanying consolidated financial statements.
     Historical capital expenditures and acquisitions of businesses, which
     represent the portion of the purchase price of acquisitions allocated to
     fixed assets and goodwill based on their fair market value, are classified
     as follows:


FINANCIAL CONDITION AND SOURCES OF LIQUIDITY

     Our primary sources of liquidity are cash and cash equivalents, marketable
securities and cash generated from operations. As of December 31, 2003, we had
cash and cash equivalents and investments in marketable securities of $1.5
billion (including $612.4 million of long-term marketable securities) and
working capital of $917.3 million. This compares to cash and cash equivalents
and investments in marketable securities of $1.3 billion (including $459.1
million of long-term marketable securities) and working capital of $618.5
million as of December 31, 2002.

     The increase in cash and cash equivalents and investments in marketable
securities, and working capital relates primarily to the issuance of our $700
million zero coupon senior exchangeable notes in June 2003, which resulted in
net proceeds of $688.5 million, partially offset by reductions in long-term debt
of $544.5 million during 2003. Cash and cash equivalents, investments in
marketable securities, and working capital were also increased during 2003 by
cash provided by operating activities totaling $395.8 million and decreased by
capital expenditures of $353.4 million during the year. The increase in working
capital was partially offset by the reclassification in 2003 of $295.3 million
principal amount of our 6.8% senior notes due April 15, 2004 to current
liabilities.

     Our funded debt-to-capital ratio was 0.48:1 as of December 31, 2003 and
0.49:1 as of December 31, 2002. Our net funded debt-to-capital ratio was 0.23:1
as of December 31, 2003 and 0.26:1 as of December 31, 2002. The funded
debt-to-capital ratio is calculated by dividing funded debt by funded debt plus
capital. Funded debt is defined as the sum of (1) short-term borrowings, (2)
current portion of long-term debt, and (3) long-term debt. Capital is defined as
shareholders' equity. The net funded debt-to-capital ratio nets cash and cash
equivalents and marketable securities ($1.5 billion and $1.3 billion as of
December 31, 2003 and 2002, respectively) against funded debt. This ratio is
calculated by dividing net funded debt by net funded debt plus capital. Both of

<PAGE>


these ratios are a method for calculating the amount of leverage a company has
in relation to its capital. Our interest coverage ratio was 6.8:1 as of December
31, 2003, compared to 6.0:1 as of December 31, 2002. The interest coverage ratio
is computed by calculating the sum of income before income taxes, interest
expense, and depreciation and amortization, and depletion expense and then
dividing by interest expense. This ratio is a method for calculating the amount
of cash flows available to cover interest expense.

     We have three letter of credit facilities and a Canadian line of credit
facility with various banks as of December 31, 2003. Availability and borrowings
under our credit facilities as of December 31, 2003 are as follows:

<Table>
<S>                                     <C>
(IN THOUSANDS)
Credit available                        $ 96,825
Letters of credit outstanding            (56,288)
                                        --------
Remaining availability                  $ 40,537
                                        --------
</Table>

     We have a shelf registration statement on file with the Securities and
Exchange Commission to allow us to offer, from time to time, up to $700 million
in debt securities, guarantees of debt securities, preferred shares, depository
shares, common shares, share purchase contracts, share purchase units and
warrants. We currently have not issued any securities registered under this
registration statement.

     Our current cash and cash equivalents, investments in marketable securities
and projected cash flow generated from current operations are expected to more
than adequately finance our sustaining capital expenditures, our debt service
requirements, including payments at maturity of our 6.8% senior notes due April
15, 2004, and all other expected cash requirements for the next twelve months.

OFF-BALANCE SHEET ARRANGEMENTS
(INCLUDING GUARANTEES)

     We are a party to certain transactions, agreements or other contractual
arrangements defined as "off-balance sheet arrangements" that could have a
material future effect on our financial position, results of operations,
liquidity and capital resources. The most significant of these off-balance sheet
arrangements involve our time charter lease obligation with Sea Mar Management
LLC and certain other agreements in which we provide financial or performance
assurance to third parties. See Related Party Transactions below and Note 12 to
our accompanying consolidated financial statements for a discussion of our Sea
Mar Management LLC time charter arrangement. Certain of our other agreements
involving financial or performance assurance to third parties serve as
guarantees, including standby letters of credit issued on behalf of insurance
carriers in conjunction with our workers' compensation insurance program and
guarantees of residual value in certain of our operating lease agreements. We
have also guaranteed payment of contingent consideration in conjunction with an
acquisition in 2002, which is based on future operating results of that
business. In addition, we have provided indemnifications to certain third
parties which serve as guarantees. These guarantees include indemnification
provided by Nabors to our stock transfer agent and our insurance carriers. We
are not able to estimate the potential future maximum payments that might be due
under our indemnification guarantees.

     Management believes the likelihood that we would be required to perform or
otherwise incur any significant losses associated with any of these guarantees
is remote. The following table summarizes the total maximum amount of financial
and performance guarantees issued by Nabors:

<Table>
<Caption>
                                                                 MAXIMUM AMOUNT
                                       ------------------------------------------------------------------
(IN THOUSANDS)                            2004          2005          2006       THEREAFTER       TOTAL
                                       ----------    ----------    ----------    ----------    ----------
<S>                                    <C>           <C>           <C>           <C>           <C>
Financial standby letters of credit    $   34,186    $       --    $       --    $       --    $   34,186
Guarantee of residual value in
 lease agreements                             347           684            65            --         1,096
Contingent consideration in
 acquisition                                1,111         1,111           278            --         2,500
                                       ----------    ----------    ----------    ----------    ----------
Total                                  $   35,644    $    1,795    $      343    $       --    $   37,782
                                       ==========    ==========    ==========    ==========    ==========
</Table>


                                   nbr {58-59}
<PAGE>

     Additionally, our $700 million zero coupon senior exchangeable notes issued
in June 2003 contain a feature whereby we will be obligated to pay contingent
interest during any six-month period from June 15 to December 14 or from
December 15 to June 14 commencing on or after June 15, 2008 for which the
average trading price of the notes for each day of the applicable five-day
trading reference period equals or exceeds 120% of the principal amount of the
notes as of the day immediately preceding the first day of the applicable
six-month interest period. The amount of contingent interest payable per note in
respect to any six-month period will equal 0.185% of the principal amount of a
note.

OTHER MATTERS

     Our Sea Mar division time charters supply vessels to offshore operators in
U.S. waters. On February 4, 2004, the United States Coast Guard took several
actions which could adversely affect our ability to do so.

The vessels are owned by one of our financing company subsidiaries, but are
operated and managed by a U.S. citizen-controlled company pursuant to long-term
bareboat charters (see Related Party Transactions below). Our Sea Mar division
time charters the vessels from this U.S. operating company in connection with
our own offshore activities in the Gulf of Mexico and in support of other
offshore operators.

On February 4, 2004, the United States Coast Guard adopted final regulations
which could cause arrangements like that utilized by Sea Mar to no longer
qualify vessels for employment in the U.S. coastwise trades. However, the final
regulations contain grandfathering provisions which could permit us to continue
coastwise marketing of the vessels until the present bareboat charters
terminate. The original term of most of these bareboat charters ends in June
2007, but the charter provides for one or more renewal terms of three to five
years. We believe the grandfathering provisions in these final regulations would
apply to these renewal terms.

Also, on February 4, 2004, the United States Coast Guard proposed a rule which,
if finally adopted, would end the grandfathering provision on February 4, 2007.
In these same proposed regulations, the United States Coast Guard is proposing a
rule under which time charters from a U.S. citizen bareboat charterer like the
charter to Sea Mar would no longer be permitted. However, we believe that if
this rule is adopted, the grandfathering provision would apply to the
preexisting Sea Mar arrangement.

Additionally, on February 4, 2004, the United States Coast Guard notified us
that it is considering an appeal of the United States Coast Guard's original
issuance in June 2002 of the coastwise trade endorsements for the vessels
bareboat chartered to the U.S. citizen qualified company. The coastwise trade
endorsements on the documents of the vessels issued by the United States Coast
Guard authorize the vessels to engage in the U.S. coastwise trade. If the appeal
is decided against us, we could lose the ability to market the vessels for use
in U.S. waters.

     During 2003 adjusted income derived from operating activities for our Sea
Mar division represented approximately 3.8% of our consolidated adjusted income
derived from operating activities. We currently expect that this percentage will
decrease to approximately 0.9% in 2004.

FORWARD-LOOKING STATEMENTS

     We often discuss expectations regarding our future markets, demand for our
products and services, and our performance in our annual and quarterly reports,
press releases, and other written and oral statements. Statements that relate to
matters that are not historical facts are "forward-looking statements" within
the meaning of the safe harbor provisions of Section 27A of the Securities Act
of 1933 and Section 21E of the Securities Exchange Act of 1934. These
"forward-looking statements" are based on an analysis of currently available
competitive, financial and economic data and our operating plans. They are
inherently uncertain and investors should recognize that events and actual
results could turn out to be significantly different from our expectations. By
way of illustration, when used in this document, words such as "anticipate,"
"believe," "expect," "plan," "intend," "estimate," "project," "will," "should,"
"could," "may," "predict" and similar expressions are intended to identify
forward-looking statements.

     You should consider the following key factors when evaluating these
forward-looking statements:

o    fluctuations in worldwide prices of and demand for natural gas and oil;

o    fluctuations in levels of natural gas and oil exploration and development
     activities;

o    fluctuations in the demand for our services;

<PAGE>

o    the existence of competitors, technological changes and developments in the
     oilfield services industry;

o    the existence of operating risks inherent in the oilfield services
     industry;

o    the existence of regulatory and legislative uncertainties;

o    the possibility of changes in tax laws;

o    the possibility of political instability, war or acts of terrorism in any
     of the countries in which we do business; and

o    general economic conditions.

     Our businesses depend, to a large degree, on the level of spending by oil
and gas companies for exploration, development and production activities.
Therefore, a sustained increase or decrease in the price of natural gas or oil,
which could have a material impact on exploration, development and production
activities, could also materially affect our financial position, results of
operations and cash flows.

     The above description of risks and uncertainties is by no means
all-inclusive, but is designed to highlight what we believe are important
factors to consider. For a more detailed description of risk factors, please
refer to our Form 10-K filed with the Securities and Exchange Commission under
Part I, Item I, "Business-Risk Factors."

RECENT ACCOUNTING PRONOUNCEMENTS

     In November 2002 the Financial Accounting Standards Board (FASB) issued
Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure
Requirements, Including Guarantees of Indebtedness of Others." FIN 45 requires
that upon issuance of certain types of guarantees, a guarantor recognize and
account for the fair value of the guarantee as a liability. FIN 45 contains
exclusions to this requirement, including the exclusion of a parent's guarantee
of its subsidiaries' debt to third parties. The initial recognition and
measurement provisions of FIN 45 have been applied on a prospective basis for
guarantees issued or modified after December 31, 2002. During 2003 we issued new
standby letters of credit which serve as guarantees under the provisions of FIN
45. The application of the recognition and measurement provisions of FIN 45 to
these guarantees was insignificant. The disclosure requirements of FIN 45 are
effective for financial statements of both interim and annual periods ending
after December 15, 2002, and are included in Note 13 to our accompanying
consolidated financial statements and under the heading Off-Balance Sheet
Arrangements (Including Guarantees) above.

     In January 2003 the FASB issued Interpretation No. 46 (FIN 46),
"Consolidation of Variable Interest Entities," which addresses the consolidation
of variable interest entities (VIEs) by business enterprises that are the
primary beneficiaries. A VIE is an entity that does not have sufficient equity
investment at risk to permit it to finance its activities without additional
subordinated financial support, or whose equity investors lack the
characteristics of a controlling financial interest. The primary beneficiary of
a VIE is the enterprise that has the majority of the risks or rewards associated
with the VIE. In December 2003 the FASB issued a revision to FIN 46,
Interpretation No. 46R (FIN 46R), to clarify some of the provisions of FIN 46,
and to exempt certain entities from its requirements. Application of FIN 46R is
required in financial statements of public entities that have interests in
structures that are commonly referred to as special-purpose entities for periods
ending after December 15, 2003. Application for all other types of VIEs is
required in financial statements for periods ending after March 15, 2004. We
have no interests in structures that are commonly referred to as special-purpose
entities and therefore have not adopted FIN 46R as of December 31, 2003. We do
not expect our adoption of FIN 46R to materially affect our financial position,
results of operations or cash flows.

     In May 2003 the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS 149 amends and clarifies
financial accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities." SFAS 149 is effective in relation to certain issues for fiscal
quarters that began prior to June 15, 2003 and for certain contracts entered
into after June 30, 2003. The adoption of SFAS 149 had no impact on our
financial position, results of operations or cash flows as of and for the year
ended December 31, 2003.

     In May 2003 the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." SFAS 150
establishes standards for how an issuer classifies and measures in its statement
of financial position certain financial instruments with characteristics of both
liabilities and equity. In accordance with the standard, financial instruments
that embody obligations for the issuer


                                   nbr {60-61}
<PAGE>

are required to be classified as liabilities. SFAS 150 is effective for such
financial instruments, except for those that apply to mandatorily redeemable
noncontrolling interests, entered into or modified after May 31, 2003, and
otherwise was effective for such financial instruments, except for those that
apply to mandatorily redeemable noncontrolling interests, at the beginning of
the third quarter of 2003. The adoption of SFAS 150 had no initial impact on our
financial position, results of operations or cash flows as of and for the year
ended December 31, 2003.

     In December 2003 the FASB issued SFAS No. 132 (revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits," that replaces
existing FASB disclosure requirements for pensions. The revised SFAS 132 is
effective for fiscal years ending after December 15, 2003, and for quarters
beginning after December 15, 2003. The disclosures related to our pension plan
included in Note 11 to our accompanying consolidated financial statements
include all relevant disclosures required by the revised SFAS 132.

RELATED PARTY TRANSACTIONS

     Pursuant to his employment agreement entered into in October 1996, we
provided an unsecured, non-interest bearing loan of approximately $2.9 million
to Nabors' Deputy Chairman, President and Chief Operating Officer. This loan is
due on September 30, 2006.

     Pursuant to their employment agreements, Nabors and its Chairman and Chief
Executive Officer, Deputy Chairman, President and Chief Operating Officer, and
certain other key employees entered into split-dollar life insurance agreements
pursuant to which we pay a portion of the premiums under life insurance policies
with respect to these individuals and, in certain instances, members of their
families. Under these agreements, we are reimbursed for such premiums upon the
occurrence of specified events, including the death of an insured individual.
Any recovery of premiums paid by Nabors could potentially be limited to the cash
surrender value of these policies under certain circumstances. As such, the
values of these policies are recorded at their respective cash surrender values
in our consolidated balance sheets. We have made premium payments to date
totaling $12.4 million related to these policies. The cash surrender value of
these policies of approximately $11.4 million and $8.7 million is included in
other long-term assets in our consolidated balance sheets as of December 31,
2003 and 2002, respectively.

     Under the Sarbanes-Oxley Act of 2002, the payment of premiums by Nabors
under the agreements with our Chairman and Chief Executive Officer and with our
Deputy Chairman, President and Chief Operating Officer may be deemed to be
prohibited loans by us to these individuals. We have paid no premiums related to
our agreements with these individuals since the adoption of the Sarbanes-Oxley
Act and have postponed premium payments related to our agreements with these
individuals.

     In the ordinary course of business, we enter into various rig leases, rig
transportation and related oilfield services agreements with our Alaskan and
Saudi Arabian unconsolidated affiliates at market prices. Additionally, we own
certain marine vessels that are chartered under a bareboat charter arrangement
to Sea Mar Management LLC, which is wholly-owned by Sea Mar Investco LLC, an
entity in which we own a 25% interest. Sea Mar Management has entered into a
time charter of these vessels with a subsidiary of ours, which then time
charters the vessels to various third-party customers. Revenues from these
business transactions totaled $81.6 million, $65.7 million and $26.9 million for
the years ended December 31, 2003, 2002 and 2001, respectively. Expenses from
these business transactions totaled $52.0 million, $32.1 million and $4.8
million for the years ended December 31, 2003, 2002 and 2001, respectively.
Additionally, we had accounts receivable from these affiliated entities of $24.0
million and $53.3 million as of December 31, 2003 and 2002, respectively. We had
accounts payable to these affiliated entities of $3.7 million and $1.1 million
as of December 31, 2003 and 2002, respectively.

CRITICAL ACCOUNTING POLICIES AND ACCOUNTING ESTIMATES

     Our consolidated financial statements are impacted by the accounting
policies used and the estimates and assumptions made by management during their
preparation. The following is a discussion of our critical accounting policies
and critical accounting estimates.

CRITICAL ACCOUNTING POLICIES

     We have identified below accounting policies that are of particular
importance to the portrayal of our financial position, results of operations and
cash flows and which require the application of significant judgment by
management.


<PAGE>

     PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment, including
renewals and betterments, are stated at cost, while maintenance and repairs are
expensed currently. Interest costs applicable to the construction of qualifying
assets are capitalized as a component of the cost of such assets. We review our
assets for impairment when events or changes in circumstances indicate that the
net book value of property, plant and equipment may not be recovered over its
remaining service life. Provisions for asset impairment are charged to income
when the sum of estimated future cash flows, on an undiscounted basis, is less
than the asset's net book value. When impairment is indicated, an impairment
charge is recorded based on an estimate of future cash flows on a discounted
basis.

     SELF-INSURANCE ACCRUALS We are self-insured for certain losses relating to
workers' compensation, employers' liability, general liability, automobile
liability and property damage. We maintain actuarially-determined accruals in
our consolidated balance sheets to cover the self-insurance retentions. We are
also self-insured for certain other losses relating to rig, equipment, property,
business interruption and political, war and terrorism risks.

     REVENUE RECOGNITION We recognize revenues and costs on daywork contracts
daily as the work progresses. For certain contracts, we receive lump-sum
payments for the mobilization of rigs and other drilling equipment. Mobilization
revenues earned and the related direct costs incurred for the mobilization are
deferred and recognized over the term of the related drilling contract. Costs
incurred to relocate rigs and other drilling equipment to areas in which a
contract has not been secured are expensed as incurred.

     We recognize revenue for top drives and instrumentation systems we
manufacture when the earnings process is complete. This generally occurs when
products have been shipped, title and risk of loss have been transferred,
collectibility is probable, and pricing is fixed and determinable.

     We recognize, as operating revenue, proceeds from business interruption
insurance claims in the period that the applicable proof of loss documentation
is received. Proceeds from casualty insurance settlements in excess of the
carrying value of damaged assets are recognized in other income in the period
that the applicable proof of loss documentation is received.

     We recognize reimbursements received for out-of-pocket expenses incurred as
revenues and account for out-of-pocket expenses as direct costs. We recognize
revenue on our interests in oil and gas properties as production occurs and
title passes.

     INCOME TAXES We are a Bermuda-exempt company and are not subject to income
taxes in Bermuda. Consequently, income taxes have been provided based on the tax
laws and rates in effect in the countries in which our operations are conducted
and income is earned. The income taxes in these jurisdictions vary
substantially. Our effective tax rate for financial statement purposes will
continue to fluctuate from year to year as our operations are conducted in
different taxing jurisdictions.

     For U.S. and other foreign jurisdiction income tax purposes, we have net
operating and other loss carryforwards that we are required to assess annually
for potential valuation allowances. We consider the sufficiency of existing
temporary differences and expected future earnings levels in determining the
amount, if any, of valuation allowance required against such carryforwards.

     We do not provide for U.S. income and foreign withholding taxes on
unremitted earnings of our international subsidiaries, as these earnings are
considered permanently reinvested. It is not practicable to estimate the amount
of deferred income taxes associated with these unremitted earnings.

     In circumstances where our drilling rigs and other assets are operating in
certain foreign taxing jurisdictions and it is expected that we will redeploy
such assets before they give rise to future tax consequences, we do not
recognize any deferred tax liabilities on the earnings from these assets.

CRITICAL ACCOUNTING ESTIMATES

     The preparation of our financial statements in conformity with GAAP
requires management to make certain estimates and assumptions. These estimates
and assumptions affect the reported amounts of assets and liabilities, the
disclosures of contingent assets and liabilities at the balance sheet date and
the amounts of revenues and expenses recognized during the reporting period. We
analyze our estimates based on our historical experience and various other
assumptions that we believe to be reasonable under the circumstances. However,
actual results could differ from such estimates. The following is a discussion
of our critical accounting estimates.

     DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT AND
INTANGIBLE ASSETS In order to depreciate and amortize our property, plant and
equipment and our intangible assets with finite lives, we estimate the useful
lives and salvage values of these items. Our estimates may be affected by such
factors as changing market conditions, technological advances in the industry or
changes in regulations governing the industry.


                                   nbr {62-63}
<PAGE>
     We provide for the depreciation of our drilling and workover rigs using the
units-of-production method over an approximate 4,900-day period, with the
exception of our jack-up rigs which are depreciated over an 8,030-day period,
after provision for salvage value. When our drilling and workover rigs are not
operating, a depreciation charge is provided using the straight-line method over
an assumed depreciable life of 20 years, with the exception of our jack-up rigs,
where a 30-year depreciable life is used.

     Depreciation on our buildings, well-servicing rigs, oilfield hauling and
mobile equipment, marine transportation and supply vessels, and other machinery
and equipment is computed using the straight-line method over the estimated
useful life of the asset after provision for salvage value (buildings - 10 to 30
years; well-servicing rigs - 3 to 15 years; marine transportation and supply
vessels - 15 to 25 years; oilfield hauling and mobile equipment and other
machinery and equipment - 3 to 10 years). Upon retirement or other disposal of
fixed assets, the cost and related accumulated depreciation are removed from the
respective accounts and any gains or losses are included in our results of
operations.

     IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT Our determination of impairment
of our property, plant and equipment requires us to estimate undiscounted future
cash flows. Actual impairment charges are recorded using an estimate of
discounted future cash flows. The determination of future cash flows requires us
to estimate dayrates and utilization in future periods, and such estimates can
change based on market conditions, technological advances in the industry or
changes in regulations governing the industry.

     INCOME TAXES Under U.S. federal tax law, the amount and availability of
loss carryforwards (and certain other tax attributes) are subject to a variety
of interpretations and restrictive tests applicable to Nabors and our
subsidiaries. The utilization of such carryforwards could be limited or
effectively lost upon certain changes in ownership. Accordingly, although we
believe substantial loss carryforwards are available to us, no assurance can be
given concerning the realization of such loss carryforwards, or whether or not
such loss carryforwards will be available in the future.

     Certain events could occur that would materially affect management's
estimates and assumptions regarding the deferred portion of our income tax
provision, including estimates of future tax rates applicable to the reversal of
tax differences, the classification of timing differences as temporary or
permanent and any valuation allowance recorded as a reduction to our deferred
tax assets.

     ALLOWANCE FOR DOUBTFUL ACCOUNTS We estimate our allowance for doubtful
accounts based on an analysis of historical collection activity and specific
identification of overdue accounts. Factors that may affect this estimate
include changes in the financial position of a major customer.

     LITIGATION AND INSURANCE RESERVES We estimate our reserves related to
litigation and insurance based on the facts and circumstances specific to the
litigation and insurance claims and our past experience with similar claims. The
actual outcome of litigated and insured claims could differ significantly from
estimated amounts. As discussed under Self-Insurance Accruals above, we maintain
actuarially-determined accruals in our consolidated balance sheets to cover
self-insurance retentions. These accruals are based on certain assumptions
developed utilizing historical data to project future losses. Loss estimates in
the calculation of these accruals are adjusted based upon actual claim
settlements and reported claims.

     FAIR VALUE OF ASSETS ACQUIRED AND LIABILITIES ASSUMED We estimate the
values of those assets acquired and liabilities assumed in business
combinations, which involves the use of various assumptions. These estimates may
be affected by such factors as changing market conditions, technological
advances in the industry or changes in regulations governing the industry. The
most significant assumptions, and the ones requiring the most judgment, involve
the estimated fair values of property, plant and equipment, and the resulting
amount of goodwill, if any. Our adoption of SFAS 142 on January 1, 2002 requires
us to test for impairment annually the goodwill and intangible assets with
indefinite useful lives recorded in business combinations. This requires us to
estimate the fair values of our own assets and liabilities at the reporting unit
level. Therefore, considerable judgment, similar to that described above in
connection with our estimation of the fair value of an acquired company, is
required to assess goodwill and certain intangible assets for impairment.

<PAGE>
     CASH FLOW ESTIMATES Our estimates of future cash flows are based on the
most recent currently available market and operating data for the applicable
asset or reporting unit at the time the estimate is made. Our cash flow
estimates are used to determine certain tax-related valuations and for asset
impairment analyses.

     STOCK-BASED COMPENSATION We account for stock-based compensation using the
intrinsic value method presented by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees." However, in accordance with SFAS No.
148, "Accounting for Stock-Based Compensation - an Amendment to FAS 123," we
must estimate the fair market value of our outstanding stock-based compensation
awards for disclosure purposes. In so doing, we use an option-pricing model
(Black-Scholes), which requires various assumptions as to interest rates,
volatility, dividend yield and expected lives of awards.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We may be exposed to certain market risks arising from the use of financial
instruments in the ordinary course of business. This risk arises primarily as a
result of potential changes in the fair market value of financial instruments
that would result from adverse fluctuations in foreign currency exchange rates,
credit risk, interest rates, and marketable and non-marketable security prices
as discussed below.

     FOREIGN CURRENCY RISK We operate in a number of international areas and are
involved in transactions denominated in currencies other than U.S. dollars,
which exposes us to foreign exchange rate risk. The most significant exposures
arise in connection with our operations in Canada and Saudi Arabia, which
usually are substantially unhedged. For our unconsolidated affiliate in Saudi
Arabia, upon renewal of our contracts, we have been converting Saudi
riyal-denominated contracts to U.S. dollar-denominated contracts in order to
reduce our exposure to the Saudi riyal, even though that currency has been
pegged to the U.S. dollar at a rate of 3.745 Saudi riyals to 1.00 U.S. dollar
since 1986. We cannot guarantee that we will be able to convert future Saudi
riyal-denominated contracts to U.S. dollar-denominated contracts or that the
Saudi riyal exchange rate will continue in effect as in the past.

     At various times, we utilize local currency borrowings (foreign
currency-denominated debt), the payment structure of customer contracts and
foreign exchange contracts to selectively hedge our exposure to exchange rate
fluctuations in connection with monetary assets, liabilities, cash flows and
commitments denominated in certain foreign currencies. A foreign exchange
contract is a foreign currency transaction, defined as an agreement to exchange
different currencies at a given future date and at a specified rate. A
hypothetical 10% decrease in the value of all our foreign currencies relative to
the U.S. dollar as of December 31, 2003 would result in an $11.2 million
decrease in the fair value of our net monetary assets denominated in currencies
other than U.S. dollars.

     CREDIT RISK Our financial instruments that potentially subject us to
concentrations of credit risk consist primarily of cash equivalents, investments
in marketable and non-marketable securities, accounts receivable, and our
interest rate swap and range cap and floor transactions. Cash equivalents, such
as deposits and temporary cash investments, are held by major banks or
investment firms. Our investments in marketable and non-marketable securities
are managed within established guidelines which limit the amounts that may be
invested with any one issuer and which provide guidance as to issuer credit
quality. We believe that the credit risk in such instruments is minimal. In
addition, our trade receivables are with a variety of U.S., international and
foreign-country national oil and gas companies. Management considers this credit
risk to be limited due to the financial resources of these companies. We perform
ongoing credit evaluations of our customers and we generally do not require
material collateral. We maintain reserves for potential credit losses, and such
losses have been within management's expectations.

     INTEREST RATE, AND MARKETABLE AND NON-MARKETABLE SECURITY PRICE RISK Our
financial instruments that are potentially sensitive to changes in interest
rates include our $1.381 billion zero coupon convertible senior debentures, our
$700 million zero coupon senior exchangeable notes, our 6.8%, 4.875% and 5.375%
senior notes, our interest rate swap and range cap and floor transactions, our
investments in debt securities (including corporate, asset-backed, U.S.
Government, Government agencies, foreign government, mortgage-backed debt and
mortgage-CMO debt securities) and our investments in overseas funds investing
primarily in a variety of public and private U.S. and non-U.S. securities
(including asset-backed securities and mortgage-backed securities, global
structured asset securitizations, whole loan mortgages, and participations in
whole loans and whole loan mortgages), which are classified as non-marketable
securities.


                                   nbr {64-65}
<PAGE>

     We may utilize derivative financial instruments that are intended to manage
our exposure to interest rate risks. The use of derivative financial instruments
could expose us to further credit risk and market risk. Credit risk in this
context is the failure of a counterparty to perform under the terms of the
derivative contract. When the fair value of a derivative contract is positive,
the counterparty would owe us, which can create credit risk for us. When the
fair value of a derivative contract is negative, we would owe the counterparty,
and therefore, we would not be exposed to credit risk. We attempt to minimize
credit risk in derivative instruments by entering into transactions with major
financial institutions that have a significant asset base. Market risk related
to derivatives is the adverse effect to the value of a financial instrument that
results from changes in interest rates. We try to manage market risk associated
with interest-rate contracts by establishing and monitoring parameters that
limit the type and degree of market risk that we undertake.

     Our $700 million zero coupon senior exchangeable notes include a contingent
interest provision, discussed under Liquidity above, which qualifies as an
embedded derivative under SFAS 133, as amended by SFAS 149. This embedded
derivative is required to be separated from the notes and valued at its fair
value at the inception of the note indenture. Any subsequent change in fair
value of this embedded derivative will be recorded in our consolidated
statements of income. The fair value of the contingent interest provision at
inception of the note indenture was nominal. In addition, there was no
significant change in the fair value of this embedded derivative through
December 31, 2003, resulting in no impact on our consolidated statement of
income for the year ended December 31, 2003.

     On October 21, 2002, we entered into an interest rate swap transaction with
a third-party financial institution to hedge our exposure to changes in the fair
value of $200 million of our fixed rate 5.375% senior notes due 2012, which has
been designated as a fair value hedge under SFAS 133, as amended by SFAS 149.
Additionally, on October 21, 2002, we purchased a LIBOR range cap and sold a
LIBOR floor, in the form of a cashless collar, with the same third-party
financial institution with the intention of mitigating and managing our exposure
to changes in the three-month U.S. dollar LIBOR rate. This transaction does not
qualify for hedge accounting treatment under SFAS 133, as amended by SFAS 149,
and any change in the cumulative fair value of this transaction will be
reflected as a gain or loss in our consolidated statements of income.

     During the years ended December 31, 2003 and 2002, we recorded interest
savings related to our interest rate swap agreement accounted for as a fair
value hedge of $6.8 million and $1.2 million, respectively, which served to
reduce interest expense. The fair value of our interest rate swap agreement is
recorded as a derivative asset, included in other long-term assets, and totaled
approximately $4.2 million and $10.1 million as of December 31, 2003 and 2002,
respectively. The carrying value of our 5.375% senior notes has been increased
by the same amount as of December 31, 2003 and 2002.

     The fair value of our range cap and floor transaction is recorded as a
derivative liability, included in other long-term liabilities, and totaled
approximately $3.7 million and $3.8 million as of December 31, 2003 and 2002,
respectively. We recorded losses of approximately $1.1 million and $3.8 million
for the years ended December 31, 2003 and 2002, respectively, related to this
derivative instrument; such amounts are included in other income in our
consolidated statements of income. The loss in the current year is comprised of
the recognition of approximately $1.2 million of expense in 2003 related to the
settlement of amounts due to the counterparty for our range cap and floor
derivative instrument discussed below, which were partially offset by a gain of
approximately $.1 million resulting from the change in cumulative fair value of
this derivative instrument during 2003. As a result of the three-month U.S.
dollar LIBOR rate being below our 2.665% floor on August 15, 2003 (such rate was
1.13%), we paid approximately $.8 million to the counterparty on November 15,
2003 as settlement for the three-month period from August 15 to November 15,
2003. As a result of the three-month U.S. dollar LIBOR rate being below our
2.665% floor on November 15, 2003 (such rate was 1.18%), we are obligated to
pay, on February 15, 2004, approximately $.8 million to the counterparty as
settlement for amounts due for the three-month period from November 15, 2003 to
February 15, 2004. We recorded the payment of approximately $.8 million made on
November 15, 2003 and approximately $.4 million of the obligation due on
February 15, 2004 as expense in other income in 2003 and will record the
remaining amount of approximately $.4 million due on February 15, 2004 in the
first quarter of 2004.

     A hypothetical 10% adverse shift in quoted interest rates as of December
31, 2003 would decrease the fair values of our interest rate swap, and range cap
and floor, by approximately $6.4 million and $.9 million, respectively.

<PAGE>


     FAIR VALUE OF FINANCIAL INSTRUMENTS The fair value of our fixed rate
long-term debt is estimated based on quoted market prices or prices quoted from
third-party financial institutions. The carrying and fair values of our
long-term debt, including the current portion, are as follows:

<Table>
<Caption>
                                                              DECEMBER 31, 2003
                                          ------------------------------------------------------
(IN THOUSANDS,                             EFFECTIVE             CARRYING
EXCEPT INTEREST RATES)                    INTEREST RATE            VALUE            FAIR VALUE
                                          -------------        -------------       -------------
<S>                                       <C>                  <C>                 <C>
4.875% senior notes due August 2009               4.884%       $     223,499       $     234,585
5.375% senior notes due August 2012               2.909%(1)          277,248(2)          290,813(2)
$700 million zero coupon senior
  exchangeable notes due June 2023                    0%             700,000             643,651
$1.381 billion zero coupon convertible
  senior debentures due February 2021               2.5%(3)          784,807             780,880
6.8% senior notes due April 2004                    6.8%             295,267             299,681
Other long-term debt                               8.25%               4,117               4,117
                                                               -------------       -------------
                                                               $   2,284,938       $   2,253,727
                                                               -------------       -------------
</Table>

----------

(1)  Includes the effect of interest savings realized from the interest rate
     swap executed on October 21, 2002.

(2)  Includes $4.2 million related to the fair value of the interest rate swap.

(3)  Represents the rate at which accretion of the original discount upon
     issuance of these debentures is charged to interest expense.

     The fair values of our cash equivalents, trade receivables and trade
payables approximate their carrying values due to the short-term nature of these
instruments. Our cash and cash equivalents and investments in marketable debt
and equity securities are included in the table below. The table provided below
does not include our investments in non-marketable securities, which are carried
at cost.

<Table>
<Caption>
                                                      DECEMBER 31, 2003
                                         --------------------------------------------
                                                                          WEIGHTED-
(IN THOUSANDS, EXCEPT INTEREST               FAIR          INTEREST        AVERAGE
RATES AND WEIGHTED-AVERAGE LIFE)             VALUE          RATES        LIFE (YEARS)
                                         ------------    ------------    ------------
<S>                                      <C>             <C>             <C>
Cash and cash equivalents                $    579,737     .71%--1.87%              .1
Marketable equity securities:
   Trading                                         --             N/A             N/A
   Available-for-sale                          48,843             N/A             N/A
Marketable debt securities:
  Commercial paper and CDs                     50,743            1.40%             .1
  Corporate debt securities                   319,327    1.26%--8.85%             1.2
  U.S. Government debt securities               7,103    4.75%--5.87%              .4
  Government agencies debt securities         285,358    1.25%--5.63%             1.0
  Mortgage-backed debt securities                 119            7.50%             --
  Mortgage-CMO debt securities                 29,275    4.50%--5.00%              --
  Asset-backed debt securities                211,585    1.35%--6.79%              .9
                                         ------------
                                         $  1,532,090
                                         ------------
</Table>

     Our investments in marketable debt securities listed in the above table and
a portion of our investments in non-marketable securities are sensitive to
changes in interest rates. Additionally, our investment portfolio of marketable
debt and equity securities, which are carried at fair value, expose us to price
risk. A hypothetical 10% decrease in the market prices for all marketable
securities as of December 31, 2003 would decrease the fair value of our
available-for-sale securities by $95.2 million.


                                   nbr {66-67}
<PAGE>

                         REPORT OF INDEPENDENT AUDITORS
                   {NABORS INDUSTRIES LTD. AND SUBSIDIARIES}


TO THE SHAREHOLDERS AND
BOARD OF DIRECTORS OF
NABORS INDUSTRIES LTD.:

     In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of income, of cash flows and of changes in
shareholders' equity present fairly, in all material respects, the financial
position of Nabors Industries Ltd. and its subsidiaries at December 31, 2003 and
2002, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2003, in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these 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 2 to the consolidated financial statements, Nabors
Industries Ltd. changed its method of accounting for goodwill effective January
1, 2002.


/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 5, 2004

<PAGE>
                           CONSOLIDATED BALANCE SHEETS
                    {NABORS INDUSTRIES LTD. AND SUBSIDIARIES}

<Table>
<Caption>
                                                                               DECEMBER 31,
                                                                       -----------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)                                   2003             2002
<S>                                                                    <C>              <C>

ASSETS
Current assets:
   Cash and cash equivalents                                           $    579,737     $    414,051
   Marketable securities                                                    339,936          457,600
   Accounts receivable, net                                                 410,487          320,299
   Inventory and supplies                                                    23,289           20,524
   Deferred income taxes                                                     36,442           32,846
   Other current assets                                                     125,756          124,588
                                                                       ------------     ------------
      TOTAL CURRENT ASSETS                                                1,515,647        1,369,908

Marketable securities                                                       612,417          459,148
Property, plant and equipment, net                                        2,990,792        2,801,067
Goodwill, net                                                               336,027          306,762
Other long-term assets                                                      147,809          126,987
                                                                       ------------     ------------
      TOTAL ASSETS                                                     $  5,602,692     $  5,063,872
                                                                       ------------     ------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
   Current portion of long-term debt                                   $    299,385     $    492,985
   Trade accounts payable                                                   128,840          109,163
   Accrued liabilities                                                      160,745          133,406
   Income taxes payable                                                       9,403           15,900
                                                                       ------------     ------------
      TOTAL CURRENT LIABILITIES                                             598,373          751,454

Long-term debt                                                            1,985,553        1,614,656
Other long-term liabilities                                                 155,667          161,753
Deferred income taxes                                                       372,824          377,554
                                                                       ------------     ------------
      TOTAL LIABILITIES                                                   3,112,417        2,905,417
                                                                       ------------     ------------
Commitments and contingencies (Note 13)

Shareholders' equity:
   Common shares, par value $.001 per share:
      Authorized common shares 400,000;
         issued and outstanding 146,656 and 144,965,respectively                147              145
   Capital in excess of par value                                         1,270,362        1,233,598
   Accumulated other comprehensive income (loss)                             99,583           (3,243)
   Retained earnings                                                      1,120,183          927,955
                                                                       ------------     ------------
      TOTAL SHAREHOLDERS' EQUITY                                          2,490,275        2,158,455
                                                                       ------------     ------------
      TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                       $  5,602,692     $  5,063,872
                                                                       ------------     ------------
</Table>

The accompanying notes are an integral part of these consolidated financial
statements.


                                   NBR {68-69}
<PAGE>
                        CONSOLIDATED STATEMENTS OF INCOME
                    {NABORS INDUSTRIES LTD. AND SUBSIDIARIES}

<Table>
<Caption>
                                                                   YEAR ENDED DECEMBER 31,
                                                       -----------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)                   2003              2002             2001
<S>                                                    <C>               <C>              <C>

Revenues and other income:

   Operating revenues                                  $  1,880,003      $  1,466,443     $  2,201,736
   Earnings from unconsolidated affiliates                   10,183            14,775           26,334
   Interest income                                           27,752            34,086           53,973
   Other income, net                                          4,908             3,708           28,650
                                                       ------------      ------------     ------------
      Total revenues and other income                     1,922,846         1,519,012        2,310,693
                                                       ------------      ------------     ------------
Costs and other deductions:
   Direct costs                                           1,276,953           973,910        1,366,967
   General and administrative expenses                      165,403           141,895          135,496
   Depreciation and amortization                            226,528           187,665          184,119
   Depletion                                                  8,599             7,700            5,777
   Interest expense                                          70,740            67,068           60,722
                                                       ------------      ------------     ------------
      Total costs and other deductions                    1,748,223         1,378,238        1,753,081
                                                       ------------      ------------     ------------
Income before income taxes                                  174,623           140,774          557,612
                                                       ------------      ------------     ------------
Income tax (benefit) expense:
   Current                                                    8,494            10,185           83,718
   Deferred                                                 (26,099)            9,100          116,444
                                                       ------------      ------------     ------------
      Total income tax (benefit) expense                    (17,605)           19,285          200,162
                                                       ------------      ------------     ------------
NET INCOME                                             $    192,228      $    121,489     $    357,450
                                                       ------------      ------------     ------------
EARNINGS PER SHARE:
   BASIC                                               $       1.31      $        .85     $       2.48
   DILUTED                                             $       1.25      $        .81     $       2.24

WEIGHTED-AVERAGE NUMBER OF COMMON
   SHARES OUTSTANDING:
   BASIC                                                    146,495           143,655          144,430
   DILUTED                                                  156,897           149,997          168,790
</Table>

The accompanying notes are an integral part of these consolidated financial
statements.

<PAGE>

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                    {NABORS INDUSTRIES LTD. AND SUBSIDIARIES}

<Table>
<Caption>
                                                                                         YEAR ENDED DECEMBER 31,
                                                                             ------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)                                         2003              2002              2001
<S>                                                                          <C>               <C>               <C>

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income                                                                   $    192,228      $    121,489      $    357,450
Adjustments to net income:
   Depreciation and amortization                                                  226,528           187,665           184,119
   Depletion                                                                        8,599             7,700             5,777
   Deferred income tax (benefit) expense                                          (26,099)            9,100           116,444
   Deferred financing costs amortization                                            5,464             5,122             6,339
   Discount amortization on long-term debt                                         25,521            30,790            31,832
   Amortization of loss on cash flow hedges                                           152                50                --
   Gains on long-term assets, net                                                  (2,476)           (4,570)          (10,246)
   (Gains) losses on marketable and non-marketable securities, net                 (6,145)           (2,877)              474
   Losses on derivative instruments                                                 1,140             1,983                --
   Sales of marketable securities, trading                                          4,484                --                --
   Foreign currency transaction gains                                                (830)             (486)             (419)
   Loss (gain) on early extinguishment of debt                                        908               202           (15,330)
   Equity in earnings from unconsolidated affiliates, net of dividends               (919)           (4,900)          (15,833)
Increase (decrease), net of effects from acquisitions, from changes in:
   Accounts receivable                                                            (30,660)           90,401            (8,454)
   Inventory and supplies                                                          (5,695)            1,712              (791)
   Other current assets                                                               (61)          (15,855)           (2,273)
   Other long-term assets                                                          (9,342)          (29,717)           18,913
   Trade accounts payable and accrued liabilities                                  22,584           (26,443)           28,638
   Income taxes payable                                                             1,454            11,725               801
   Other long-term liabilities                                                    (11,004)           17,785             6,698
                                                                             ------------      ------------      ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES                                         395,831           400,876           704,139
                                                                             ------------      ------------      ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
   Purchases of marketable securities, available-for-sale                      (1,429,545)         (745,383)         (804,067)
   Sales and maturities of marketable securities, available-for-sale            1,393,638           542,133           431,498
   Purchases of non-marketable securities, net                                    (29,496)          (15,000)               --
   Cash paid for acquisitions of businesses, net                                       --          (135,652)          (66,352)
   Capital expenditures                                                          (353,406)         (326,536)         (712,605)
   Cash paid for other current assets                                                  --            (8,725)               --
   Proceeds from sales of assets and insurance claims                              10,476            34,877            15,067
                                                                             ------------      ------------      ------------
NET CASH USED FOR INVESTING ACTIVITIES                                           (408,333)         (654,286)       (1,136,459)
                                                                             ------------      ------------      ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
   (Decrease) increase in cash overdrafts                                            (778)           (3,658)            2,395
   Decrease in restricted cash                                                      1,925               210               692
   Decrease in short-term borrowings, net                                              --              (844)               --
   Proceeds from long-term debt                                                   700,000           495,904           840,338
   Reduction of long-term debt                                                   (544,479)          (30,831)         (156,001)
   Debt issuance costs                                                            (11,525)           (2,945)          (12,879)
   Proceeds from issuance of common shares                                         26,341            12,850             8,219
   Repurchase of common shares                                                         --            (2,486)         (247,963)
   Payments related to cash flow hedges                                                --            (1,494)               --
                                                                             ------------      ------------      ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES                                         171,484           466,706           434,801
                                                                             ------------      ------------      ------------
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS                        6,704             2,312            (1,350)
                                                                             ------------      ------------      ------------
NET INCREASE IN CASH AND CASH EQUIVALENTS                                         165,686           215,608             1,131
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD                                    414,051           198,443           197,312
                                                                             ------------      ------------      ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD                                     $    579,737      $    414,051      $    198,443
                                                                             ------------      ------------      ------------
</Table>

The accompanying notes are an integral part of these consolidated financial
statements.

                                   NBR {70-71}
<PAGE>
           CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
                    {NABORS INDUSTRIES LTD. AND SUBSIDIARIES}

<Table>
<Caption>
                                                                                          ACCUMULATED OTHER
                                                                                     COMPREHENSIVE INCOME (LOSS)
                                                                                     ---------------------------
                                                                                      UNREALIZED       MINIMUM
                                                COMMON SHARES           CAPITAL IN   GAINS (LOSSES)    PENSION
                                         --------------------------       EXCESS     ON MARKETABLE    LIABILITY
                                           SHARES        PAR VALUE     OF PAR VALUE   SECURITIES     ADJUSTMENT
                                         -----------    -----------    ------------  -------------   -----------
<S>                                      <C>            <C>            <C>            <C>            <C>
(IN THOUSANDS)

BALANCES, DECEMBER 31, 2000                  147,155    $    14,715    $ 1,145,847    $    15,897    $        --
                                         -----------    -----------    -----------    -----------    -----------
Comprehensive income (loss):
   Net income
   Translation adjustment
   Unrealized losses on
       marketable securities,
       net of income tax
       benefit of $1,974                                                                   (3,361)
       Less: reclassification
          adjustment for gains
          included in net income,
          net of income taxes of $74                                                         (126)
                                         -----------    -----------    -----------    -----------    -----------
          Total comprehensive
          income (loss)                           --             --             --         (3,487)            --
                                         -----------    -----------    -----------    -----------    -----------
Issuance of common shares
   for stock options exercised                   556             56          8,163
Tax effect of stock
   option deductions                                                       (62,474)
Repurchase of common shares
                                         -----------    -----------    -----------    -----------    -----------
       Subtotal                                  556             56        (54,311)            --             --
                                         -----------    -----------    -----------    -----------    -----------
BALANCES, DECEMBER 31, 2001                  147,711    $    14,771    $ 1,091,536    $    12,410    $        --
                                         -----------    -----------    -----------    -----------    -----------

<Caption>
                                              ACCUMULATED OTHER
                                         COMPREHENSIVE INCOME (LOSS)
                                         ---------------------------
                                           UNREALIZED
                                             LOSS ON     CUMULATIVE                                     TOTAL
                                            CASH FLOW    TRANSLATION     RETAINED      TREASURY     SHAREHOLDERS'
                                             HEDGES      ADJUSTMENT      EARNINGS        STOCK         EQUITY
                                           -----------   -----------    -----------   -----------   -------------
<S>                                      <C>           <C>            <C>           <C>            <C>
(IN THOUSANDS)

BALANCES, DECEMBER 31, 2000                $        --   $    (8,803)   $   643,629   $    (4,817)   $ 1,806,468
                                           -----------   -----------    -----------   -----------    -----------
Comprehensive income (loss):
   Net income                                                               357,450                      357,450
   Translation adjustment                                       (347)                                       (347)
   Unrealized losses on
       marketable securities,
       net of income tax
       benefit of $1,974                                                                                  (3,361)
       Less: reclassification
          adjustment for gains
          included in net income,
          net of income taxes of $74                                                                        (126)
                                           -----------   -----------    -----------   -----------    -----------
          Total comprehensive
          income (loss)                             --          (347)       357,450            --        353,616
                                           -----------   -----------    -----------   -----------    -----------
Issuance of common shares
   for stock options exercised                                                                             8,219
Tax effect of stock
   option deductions                                                                                     (62,474)
Repurchase of common shares                                                              (247,963)      (247,963)
                                           -----------   -----------    -----------   -----------    -----------
       Subtotal                                     --            --             --      (247,963)      (302,218)
                                           -----------   -----------    -----------   -----------    -----------
BALANCES, DECEMBER 31, 2001                $        --   $    (9,150)   $ 1,001,079   $  (252,780)   $ 1,857,866
                                           -----------   -----------    -----------   -----------    -----------
</Table>

The accompanying notes are an integral part of these consolidated financial
statements.


<PAGE>

           CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
                    {NABORS INDUSTRIES LTD. AND SUBSIDIARIES}

<Table>
<Caption>
                                                                                          ACCUMULATED OTHER
                                                                                     COMPREHENSIVE INCOME (LOSS)
                                                                                     ---------------------------
                                                                                      UNREALIZED       MINIMUM
                                                COMMON SHARES           CAPITAL IN   GAINS (LOSSES)    PENSION
                                         --------------------------       EXCESS     ON MARKETABLE    LIABILITY
                                           SHARES        PAR VALUE     OF PAR VALUE   SECURITIES     ADJUSTMENT
                                         -----------    -----------    ------------  -------------   -----------
<S>                                      <C>            <C>            <C>            <C>            <C>
(IN THOUSANDS)

BALANCES, DECEMBER 31, 2001                  147,711    $    14,771    $ 1,091,536    $    12,410    $        --
                                         -----------    -----------    -----------    -----------    -----------

Comprehensive income (loss):
   Net income
   Translation adjustment
   Unrealized losses on
       marketable securities,
       net of income tax
       benefit of $3,118                                                                   (5,309)
       Less: reclassification
         adjustment for gains
         included in net income,
         net of income taxes
         of $855                                                                           (1,455)
   Minimum pension liability
       adjustment, net of
       income taxes of $1,295                                                                             (2,205)
   Unrealized loss on cash
       flow hedges, net of
       income taxes of $848
                                         -----------    -----------    -----------    -----------    -----------
       Total comprehensive
       income (loss)                              --             --             --         (6,764)        (2,205)
                                         -----------    -----------    -----------    -----------    -----------
Issuance of common shares
   for stock options exercised                   806             64         10,210
Issuance of common shares
   in connection with the
   Bayard warrants exercised                      18              2             (2)
Issuance of common shares
   in connection with the
   Enserco acquisition                         2,638            264        162,497
Issuance of common shares
   in connection with the
   Ryan acquisition                              220                        11,636
Nabors Exchangeco
   shares exchanged                              485             19            (19)
Tax effect of stock
   option deductions                                                           842
Repurchase of common shares                      (91)                         (799)
Put option on common shares                                                  2,576
Retirement of treasury stock                  (6,822)          (682)       (59,172)
Change in par value                                         (14,293)        14,293
                                         -----------    -----------    -----------    -----------    -----------
       Subtotal                               (2,746)       (14,626)       142,062             --             --
                                         -----------    -----------    -----------    -----------    -----------
BALANCES, DECEMBER 31, 2002                  144,965    $       145    $ 1,233,598    $     5,646    $    (2,205)
                                         -----------    -----------    -----------    -----------    -----------

<Caption>
                                              ACCUMULATED OTHER
                                         COMPREHENSIVE INCOME (LOSS)
                                         ---------------------------
                                           UNREALIZED
                                             LOSS ON     CUMULATIVE                                      TOTAL
                                            CASH FLOW    TRANSLATION     RETAINED      TREASURY      SHAREHOLDERS'
                                             HEDGES      ADJUSTMENT      EARNINGS        STOCK          EQUITY
                                           -----------   -----------    -----------   -----------    -------------
<S>                                      <C>             <C>            <C>           <C>            <C>
(IN THOUSANDS)

BALANCES, DECEMBER 31, 2001                 $        --    $    (9,150)   $ 1,001,079    $  (252,780)   $ 1,857,866
                                            -----------    -----------    -----------    -----------    -----------

Comprehensive income (loss):
   Net income                                                                 121,489                       121,489
   Translation adjustment                                        3,910                                        3,910
   Unrealized losses on
       marketable securities,
       net of income tax
       benefit of $3,118                                                                                     (5,309)
       Less: reclassification
         adjustment for gains
         included in net income,
         net of income taxes
         of $855                                                                                             (1,455)
   Minimum pension liability
       adjustment, net of
       income taxes of $1,295                                                                                (2,205)
   Unrealized loss on cash
       flow hedges, net of
       income taxes of $848                      (1,444)                                                     (1,444)
                                            -----------    -----------    -----------    -----------    -----------
       Total comprehensive
       income (loss)                             (1,444)         3,910        121,489             --        114,986
                                            -----------    -----------    -----------    -----------    -----------
Issuance of common shares
   for stock options exercised                                                                               10,274
Issuance of common shares
   in connection with the
   Bayard warrants exercised                                                                                     --
Issuance of common shares
   in connection with the
   Enserco acquisition                                                                                      162,761
Issuance of common shares
   in connection with the
   Ryan acquisition                                                                                          11,636
Nabors Exchangeco
   shares exchanged                                                                                              --
Tax effect of stock
   option deductions                                                                                            842
Repurchase of common shares                                                    (1,687)                       (2,486)
Put option on common shares                                                                                   2,576
Retirement of treasury stock                                                 (192,926)       252,780             --
Change in par value                                                                                              --
                                            -----------    -----------    -----------    -----------    -----------
       Subtotal                                      --             --       (194,613)       252,780        185,603
                                            -----------    -----------    -----------    -----------    -----------
BALANCES, DECEMBER 31, 2002                 $    (1,444)   $    (5,240)   $   927,955    $        --    $ 2,158,455
                                            -----------    -----------    -----------    -----------    -----------
</Table>

The accompanying notes are an integral part of these consolidated financial
statements.

                                   NBR {72-73}
<PAGE>

           CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
                    {NABORS INDUSTRIES LTD. AND SUBSIDIARIES}

<Table>
<Caption>
                                                                                          ACCUMULATED OTHER
                                                                                     COMPREHENSIVE INCOME (LOSS)
                                                                                     ---------------------------
                                                                                      UNREALIZED       MINIMUM
                                                COMMON SHARES           CAPITAL IN   GAINS (LOSSES)    PENSION
                                         --------------------------       EXCESS     ON MARKETABLE    LIABILITY
                                           SHARES        PAR VALUE     OF PAR VALUE   SECURITIES     ADJUSTMENT
                                         -----------    -----------    ------------  -------------   -----------
<S>                                      <C>            <C>            <C>            <C>            <C>
(IN THOUSANDS)

BALANCES, DECEMBER 31, 2002                  144,965    $       145    $ 1,233,598   $     5,646    $    (2,205)
                                         -----------    -----------    -----------   -----------    -----------

Comprehensive income (loss):
   Net income
   Translation adjustment
   Unrealized gains on
       marketable securities,
       net of income taxes
       of $867                                                                             1,476
       Less: reclassification
          adjustment for gains
          included in net income,
          net of income taxes
          of $1,264                                                                       (2,153)
   Minimum pension
       liability adjustment, net
       of income taxes $358                                                                                (610)
   Amortization of loss on
       cash flow hedges, net of
       income taxes of $88
                                         -----------    -----------    -----------   -----------    -----------
       Total comprehensive
       income (loss)                              --             --             --          (677)          (610)
                                         -----------    -----------    -----------   -----------    -----------
Issuance of common shares
   for stock options exercised                 1,234              2         20,339
Issuance of common shares
   in connection with the New
   Prospect warrants exercised                   200                         6,000
Issuance of common shares
   in connection with the
   Enserco warrants exercised                     49
Nabors Exchangeco
   shares exchanged                              208
Tax effect of stock
   option deductions                                                        10,425
                                         -----------    -----------    -----------   -----------    -----------
       Subtotal                                1,691              2         36,764            --             --
                                         -----------    -----------    -----------   -----------    -----------
BALANCES, DECEMBER 31, 2003                  146,656    $       147    $ 1,270,362   $     4,969    $    (2,815)
                                         -----------    -----------    -----------   -----------    -----------

<Caption>
                                               ACCUMULATED OTHER
                                          COMPREHENSIVE INCOME (LOSS)
                                          ---------------------------
                                            UNREALIZED
                                              LOSS ON     CUMULATIVE                                     TOTAL
                                             CASH FLOW    TRANSLATION     RETAINED      TREASURY     SHAREHOLDERS'
                                              HEDGES      ADJUSTMENT      EARNINGS        STOCK         EQUITY
                                            -----------   -----------    -----------   -----------   -------------
<S>                                       <C>           <C>            <C>           <C>            <C>
(IN THOUSANDS)

BALANCES, DECEMBER 31, 2002                 $    (1,444)   $    (5,240)   $   927,955   $        --   $ 2,158,455
                                            -----------    -----------    -----------   -----------   -----------

Comprehensive income (loss):
   Net income                                                                 192,228                     192,228
   Translation adjustment                                      103,963                                    103,963
   Unrealized gains on
       marketable securities,
       net of income taxes
       of $867                                                                                              1,476
       Less: reclassification
          adjustment for gains
          included in net income,
          net of income taxes
          of $1,264                                                                                        (2,153)
   Minimum pension
       liability adjustment, net
       of income taxes $358                                                                                  (610)
   Amortization of loss on
       cash flow hedges, net of
       income taxes of $88                          150                                                       150
                                            -----------    -----------    -----------   -----------   -----------
       Total comprehensive
       income (loss)                                150        103,963        192,228            --       295,054
                                            -----------    -----------    -----------   -----------   -----------
Issuance of common shares
   for stock options exercised                                                                             20,341
Issuance of common shares
   in connection with the New
   Prospect warrants exercised                                                                              6,000
Issuance of common shares
   in connection with the
   Enserco warrants exercised                                                                                  --
Nabors Exchangeco
   shares exchanged                                                                                            --
Tax effect of stock
   option deductions                                                                                       10,425
                                            -----------    -----------    -----------   -----------   -----------
       Subtotal                                      --             --             --            --        36,766
                                            -----------    -----------    -----------   -----------   -----------
BALANCES, DECEMBER 31, 2003                 $    (1,294)   $    98,723    $ 1,120,183   $        --   $ 2,490,275
                                            -----------    -----------    -----------   -----------   -----------
</Table>

The accompanying notes are an integral part of these consolidated financial
statements.

<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                    (NABORS INDUSTRIES LTD. AND SUBSIDIARIES)


1 NATURE OF OPERATIONS

     Nabors is the largest land drilling contractor in the world, with almost
600 land drilling rigs. We conduct oil, gas and geothermal land drilling
operations in the U.S. Lower 48 states, Alaska, Canada, South and Central
America, the Middle East, the Far East and Africa. Nabors also is one of the
largest land well-servicing and workover contractors in the United States and
Canada. We own approximately 750 land workover and well-servicing rigs in the
United States, primarily in the southwestern and western United States, and
approximately 200 land workover and well-servicing rigs in Canada. Nabors is a
leading provider of offshore platform workover and drilling rigs, and owns
45 platform, 16 jack-up and three barge rigs in the Gulf of Mexico and
international markets. These rigs provide well-servicing, workover and drilling
services. We also have a 50% ownership interest in a joint venture in Saudi
Arabia, which owns 17 rigs.

     To further supplement and complement our primary business, we offer a wide
range of ancillary well-site services, including engineering, transportation,
construction, maintenance, well logging, directional drilling, rig
instrumentation, data collection and other support services, in selected
domestic and international markets. Our land transportation and hauling fleet
includes approximately 240 rig and oilfield equipment hauling tractor-trailers
and a number of cranes, loaders and light-duty vehicles. We maintain
approximately 300 fluid hauling trucks, approximately 800 fluid storage tanks,
ten saltwater disposal wells and other auxiliary equipment used in drilling,
workover and well-servicing operations in the United States. In addition, we
time charter a fleet of 31 marine transportation and supply vessels, which
provide transportation of drilling materials, supplies and crews for offshore
operations primarily in the Gulf of Mexico. We manufacture and lease or sell top
drives for a broad range of drilling applications, directional drilling systems,
rig instrumentation and data collection equipment and rig reporting software. We
have also made selective investments in oil and gas exploration, development and
production activities, most recently with El Paso Corporation (see discussion
included in Note 13).

     The majority of our business is conducted through our various Contract
Drilling operating segments, which include our drilling, workover and
well-servicing operations, on land and offshore. Our operating segments engaged
in marine transportation and supply services, drilling technology and top drive
manufacturing, directional drilling, rig instrumentation and software, and
construction and logistics operations are aggregated in a category labeled Other
Operating Segments for segment reporting purposes. Our limited oil and gas
exploration, development and production operations are included in a category
labeled Oil and Gas for segment reporting purposes.

     Our businesses depend, to a large degree, on the level of spending by oil
and gas companies for exploration, development and production activities.
Therefore, a sustained increase or decrease in the price of natural gas or oil,
which could have a material impact on exploration, development and production
activities, also could materially affect our financial position, results of
operations and cash flows.

     As used in this Report, "we," "us," "our" and "Nabors" means Nabors
Industries Ltd. and, where the context requires, includes our subsidiaries.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

     Our consolidated financial statements include the accounts of Nabors and
all majority-owned subsidiaries. All significant intercompany accounts and
transactions are eliminated in consolidation.

     Investments in entities where we have the ability to exert significant
influence, but where we do not control their operating and financial policies,
are accounted for using the equity method. Our share of the net income of these
entities is recorded as Earnings from unconsolidated affiliates in our
consolidated statements of income, and our investment in these entities is
carried as a single amount in our consolidated balance sheets. Investments in
net assets of unconsolidated affiliates accounted for using the equity method
totaled $58.1 million and $58.6 million as of December 31,



                                  nbr (74-75)


<PAGE>



2003 and 2002, respectively, and are included in other long-term assets in our
consolidated balance sheets.

RECLASSIFICATIONS

     Certain reclassifications have been made to prior periods to conform to the
current period presentation, with no effect on our consolidated financial
position, results of operations or cash flows.

CASH AND CASH EQUIVALENTS

     Cash and cash equivalents include demand deposits and various other
short-term investments with original maturities of three months or less.

MARKETABLE AND NON-MARKETABLE SECURITIES

     Marketable securities consist of equity securities, certificates of
deposit, corporate debt securities, U.S. Government debt securities, government
agencies debt securities, foreign government debt securities, mortgage-backed
debt securities and asset-backed debt securities. Securities classified as
available-for-sale or trading are stated at fair value. Unrealized holding gains
and losses for available-for-sale securities are excluded from earnings and,
until realized, are reported net of taxes in a separate component of
shareholders' equity. Unrealized and realized gains and losses on securities
classified as trading are reported in earnings currently.

     In computing realized gains and losses on the sale of equity securities,
the specific identification method is used. In accordance with this method, the
cost of the equity securities sold is determined using the specific cost of the
security when originally purchased.

     We are also invested in overseas funds investing primarily in a variety of
public and private U.S. and non-U.S. securities (including asset-backed
securities and mortgage-backed securities, global structured asset
securitizations, whole loan mortgages, and participations in whole loans and
whole loan mortgages). These investments are classified as non-marketable,
because they do not have published fair values, and are recorded at cost in our
consolidated balance sheets as a component of other current assets. Gains or
losses are realized, as other income, when distributions are made from the
funds.

INVENTORY AND SUPPLIES

     Inventory and supplies are composed of top drives and drilling
instrumentation systems manufactured by our subsidiaries for resale. Inventory
and supplies are valued at the lower of weighted-average cost or market value.

PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment, including renewals and betterments, are
stated at cost, while maintenance and repairs are expensed currently. Interest
costs applicable to the construction of qualifying assets are capitalized as a
component of the cost of such assets. We provide for the depreciation of our
drilling and workover rigs using the units-of-production method over an
approximate 4,900-day period, with the exception of our jack-up rigs which are
depreciated over an 8,030-day period, after provision for salvage value. When
our drilling and workover rigs are not operating, a depreciation charge is
provided using the straight-line method over an assumed depreciable life of 20
years, with the exception of our jack-up rigs, where a 30-year depreciable life
is used. Effective October 1, 2001, we changed the depreciable lives of our
drilling and workover rigs from 4,200 to 4,900 active days, our jack-up rigs
from 4,200 to 8,030 active days and certain other drilling equipment lives, to
better reflect the estimated useful lives of these assets. The effect of this
change in accounting estimate was accounted for on a prospective basis beginning
October 1, 2001 and increased net income by approximately $14.7 million ($.09
per diluted share), $19.7 million ($.13 per diluted share) and $5.5 million
($.03 per diluted share) for the years ended December 31, 2003, 2002 and 2001,
respectively.

     Depreciation on our buildings, well-servicing rigs, oilfield hauling and
mobile equipment, marine transportation and supply vessels, and other machinery
and equipment is computed using the straight-line method over the estimated
useful life of the asset after provision for salvage value (buildings - 10 to 30
years; well-servicing rigs - 3 to 15 years; marine transportation and supply
vessels - 15 to 25 years; oilfield hauling and mobile equipment and other
machinery and equipment - 3 to 10 years). Amortization of capitalized leases is
included in depreciation and amortization expense. Upon retirement or other
disposal of fixed assets, the cost and related accumulated depreciation are
removed from the respective accounts and any gains or losses are included in our
results of operations.



<PAGE>


     We review our assets for impairment when events or changes in circumstances
indicate that the net book value of property, plant and equipment may not be
recovered over its remaining service life. Provisions for asset impairment are
charged to income when the sum of estimated future cash flows, on an
undiscounted basis, is less than the asset's net book value. Actual impairment
charges are recorded using an estimate of discounted future cash flows. The
determination of future cash flows requires us to estimate day rates and
utilization in future periods, and such estimates can change based on market
conditions, technological advances in the industry or changes in regulations
governing the industry. There were no impairment charges related to assets held
for use recorded by Nabors in 2003, 2002 or 2001. In 2002 we reclassified four
supply vessels to available-for-sale as we intended to sell these vessels in
2003. Accordingly, we reduced the carrying values of these assets to levels
approximating their respective fair values, resulting in a charge to other
income of $3.7 million in 2002. Three of these supply vessels were sold in 2003
for amounts approximating their current carrying values, resulting in a gain of
$.2 million recorded in other income for the year ended December 31, 2003. The
fourth supply vessel was sold in January 2004 for an amount that approximated
its carrying value.

OIL AND GAS PROPERTIES

     We follow the successful efforts method of accounting for our oil and gas
activities. Under the successful efforts method, lease acquisition costs and all
development costs are capitalized. Proved oil and gas properties are reviewed
when circumstances suggest the need for such a review and, if required, the
proved properties are written down to their estimated fair value. Unproved
properties are reviewed quarterly to determine if there has been impairment of
the carrying value, with any such impairment charged to expense in that period.
Estimated fair value includes the estimated present value of all reasonably
expected future production, prices and costs. Exploratory drilling costs are
capitalized until the results are determined. If proved reserves are not
discovered, the exploratory drilling costs are expensed. Interest costs related
to financing major oil and gas projects in progress are capitalized until the
projects are evaluated or until the projects are substantially complete and
ready for their intended use if the projects are evaluated as successful. Other
exploratory costs are expensed as incurred. Our provision for depletion is based
on the capitalized costs as determined above and is determined on a
property-by-property basis using the units-of-production method, with costs
being amortized over proved developed reserves.

GOODWILL

     Goodwill represents the cost in excess of fair value of the net assets of
companies acquired. Prior to January 1, 2002, goodwill was amortized using the
straight-line method over 30 years and was recorded net of accumulated
amortization of $16.1 million as of December 31, 2001. Effective January 1,
2002, we adopted Statement of Financial Accounting Standards (SFAS) No. 142,
"Goodwill and Other Intangible Assets." SFAS 142 supersedes Accounting
Principles Board (APB) Opinion No. 17, which stated that goodwill acquired as a
result of a purchase method business combination and all other intangible assets
were subject to amortization. APB 17 also mandated a maximum period of 40 years
for that amortization. SFAS 142 presumes that all goodwill and intangible assets
that have indefinite useful lives will not be subject to amortization, but
rather will be tested at least annually for impairment. In addition, the
standard provides specific guidance on how to determine and measure goodwill
impairment. Intangible assets that have finite useful lives will continue to be
amortized over their useful lives, but without the constraint of a 40-year
maximum amortization period.

     During the second quarter of 2002 we performed our initial goodwill
impairment assessment as required by SFAS 142. As part of that assessment, we
determined that our 11 business units, as of January 1, 2002, represented our
reporting units as defined by SFAS 142. We determined the aggregate carrying
values and fair values of all such reporting units, which were measured as of
the January 1, 2002 adoption date. We calculated the fair value of each
reporting unit based on discounted cash flows and determined there was no
goodwill impairment. In instances where assets acquired and liabilities assumed
in a business combination are assigned solely to one of our business units, the
amount of goodwill resulting from that acquisition is assigned in full to



                                  nbr (76-77)


<PAGE>


that business unit. In instances where assets and liabilities are split between
more than one business unit, we assign goodwill to our business units based on
the respective fair values of the fixed assets assigned to each business unit.
In the second quarter of 2003 we performed our annual assessment of goodwill
impairment and determined there was no goodwill impairment.

     If the provisions of SFAS 142 had been in effect during the periods prior
to January 1, 2002, goodwill amortization would not have been recorded,
increasing net income and earnings per share as follows:

<Table>
<Caption>
(In thousands, except per share amounts)          2001
<S>                                          <C>
Reported net income                          $       357,450
Add back: goodwill amortization, net of
  related income tax benefit of $2,572                 4,573
                                             ---------------

Adjusted net income                          $       362,023
                                             ---------------

Earnings per share:
 Basic:
  Reported                                   $          2.48
  Goodwill amortization                                  .03
                                             ---------------

  Adjusted                                   $          2.51
                                             ---------------

 Diluted:
  Reported                                   $          2.24
  Goodwill amortization                                  .02
                                             ---------------

  Adjusted                                   $          2.26
                                             ---------------
</Table>


     The change in the carrying amount of goodwill for our various Contract
Drilling segments and our Other Operating Segments for the years ended December
31, 2003 and 2002 is as follows:

<Table>
<Caption>
(IN THOUSANDS)                                   ACQUISITIONS
                                                     AND           CUMULATIVE
                                BALANCE AS OF    PURCHASE PRICE    TRANSLATION                        BALANCE AS OF
                              DECEMBER 31, 2001   ADJUSTMENTS       ADJUSTMENT          OTHER       DECEMBER 31, 2002
                              -----------------  --------------  ---------------   ---------------  -----------------
<S>                            <C>               <C>             <C>               <C>              <C>
CONTRACT DRILLING:
  U.S. Lower 48 Land Drilling  $        28,785   $           --  $            --   $           (85)  $        28,700
  U.S. Land Well-servicing              43,741               --               --                --            43,741
  U.S. Offshore                         29,583               --               --                --            29,583
  Alaska                                19,995               --               --                --            19,995
  Canada                                 8,209          107,419           (2,837)               --           112,791
  International                         25,145               --               --                --            25,145
                               ---------------   --------------  ---------------   ---------------   ---------------
  Subtotal Contract Drilling           155,458          107,419           (2,837)              (85)          259,955
OTHER OPERATING SEGMENTS                43,590            3,217               --                --            46,807
                               ---------------   --------------  ---------------   ---------------   ---------------
Total                          $       199,048   $      110,636  $        (2,837)  $           (85)  $       306,762
                               ---------------   --------------  ---------------   ---------------   ---------------
</Table>


<Table>
<Caption>
(IN THOUSANDS)                                    ACQUISITIONS
                                                      AND          CUMULATIVE
                                BALANCE AS OF    PURCHASE PRICE   TRANSLATION                        BALANCE AS OF
                              DECEMBER 31, 2002    ADJUSTMENTS     ADJUSTMENT         OTHER        DECEMBER 31, 2003
                              -----------------  --------------  ---------------  ---------------  -----------------
<S>                            <C>               <C>             <C>              <C>              <C>
CONTRACT DRILLING:
  U.S. Lower 48 Land Drilling  $        28,700   $           --  $            --  $         1,276   $        29,976
  U.S. Land Well-servicing              43,741               --               --               --            43,741
  U.S. Offshore                         29,583               --               --          (11,580)           18,003
  Alaska                                19,995               --               --               --            19,995
  Canada                               112,791            1,378           24,398               --           138,567
  International                         25,145               --               --           11,580            36,725
                               ---------------   --------------  ---------------  ---------------   ---------------

  Subtotal Contract Drilling           259,955            1,378           24,398            1,276           287,007
OTHER OPERATING SEGMENTS                46,807            1,601              612               --            49,020
                               ---------------   --------------  ---------------  ---------------   ---------------

Total                          $       306,762   $        2,979  $        25,010  $         1,276   $       336,027
                               ---------------   --------------  ---------------  ---------------   ---------------
</Table>


     Our Oil and Gas segment does not have any goodwill. Goodwill totaling
approximately $7.3 million is expected to be deductible for tax purposes.



<PAGE>


DERIVATIVE FINANCIAL INSTRUMENTS

     We record derivative financial instruments (including certain derivative
instruments embedded in other contracts) in our consolidated balance sheets at
fair value as either assets or liabilities. The accounting for changes in the
fair value of a derivative instrument depends on the intended use of the
derivative and the resulting designation, which is established at the inception
of a derivative. Accounting for derivatives qualifying as fair value hedges
allows a derivative's gains and losses to offset related results on the hedged
item in our consolidated statement of income. For derivative instruments
designated as cash flow hedges, changes in fair value, to the extent the hedge
is effective, are recognized in other comprehensive income until the hedged item
is recognized in earnings. Hedge effectiveness is measured quarterly based on
the relative cumulative changes in fair value between the derivative contract
and the hedged item over time. Any change in fair value resulting from
ineffectiveness is recognized immediately in earnings. Any change in fair value
of derivative financial instruments that are speculative in nature and do not
qualify for hedge accounting treatment is also recognized immediately in
earnings.

LITIGATION AND INSURANCE RESERVES

     We estimate our reserves related to litigation and insurance based on the
facts and circumstances specific to the litigation and insurance claims and our
past experience with similar claims. We maintain actuarially-determined
accruals in our consolidated balance sheets to cover self-insurance retentions
(Note 13).

REVENUE RECOGNITION

     We recognize revenues and costs on daywork contracts daily as the work
progresses. For certain contracts, we receive lump-sum payments for the
mobilization of rigs and other drilling equipment. Mobilization revenues
earned and the related direct costs incurred for the mobilization are deferred
and recognized over the term of the related drilling contract. Costs incurred to
relocate rigs and other drilling equipment to areas in which a contract has not
been secured are expensed as incurred.

     We recognize revenue for top drives and instrumentation systems we
manufacture when the earnings process is complete. This generally occurs when
products have been shipped, title and risk of loss have been transferred,
collectibility is probable, and pricing is fixed and determinable.

     We recognize, as operating revenue, proceeds from business interruption
insurance claims in the period that the applicable proof of loss documentation
is received. Proceeds from casualty insurance settlements in excess of the
carrying value of damaged assets are recognized in other income in the period
that the applicable proof of loss documentation is received.

     We recognize reimbursements received for out-of-pocket expenses incurred
as revenues and account for out-of-pocket expenses as direct costs.

     We recognize revenue on our interests in oil and gas properties as
production occurs and title passes.

INCOME TAXES

     We are a Bermuda-exempt company and are not subject to income taxes in
Bermuda. Consequently, income taxes have been provided based on the tax laws and
rates in effect in the countries in which our operations are conducted and
income is earned. The income taxes in these jurisdictions vary substantially.
Our effective tax rate for financial statement purposes will continue to
fluctuate from year to year as our operations are conducted in different
taxing jurisdictions.

     For U.S. and other foreign jurisdiction income tax purposes, we have net
operating and other loss carryforwards that we are required to assess annually
for potential valuation allowances. We consider the sufficiency of existing
temporary differences and expected future earnings levels in determining the
amount, if any, of valuation allowance required against such carryforwards.

     We do not provide for U.S. income and foreign withholding taxes on
unremitted earnings of our international subsidiaries, as these earnings are
considered permanently reinvested. Unremitted earnings, representing tax basis
accumulated earnings and profits, totaled approximately $453.2 million, $377.2
million and $212.0 million as of December 31, 2003, 2002 and 2001, respectively.
It is not practicable to estimate the amount of deferred income taxes associated
with these unremitted earnings.

     In circumstances where our drilling rigs and other assets are operating in
certain foreign taxing jurisdictions and it is expected that we will redeploy
such assets before they give rise to future tax consequences, we do not
recognize any deferred tax liabilities on the earnings from these assets.

     Nabors realizes an income tax benefit associated with certain stock options
issued under its stock option plans. This benefit, which is not reflected in our
consolidated income statements, results in a reduction in income taxes payable
and an increase in capital in excess of par value.



                                  nbr (78-79)


<PAGE>


FOREIGN CURRENCY TRANSLATION

     For certain of our foreign subsidiaries, such as those in Canada and
Argentina, the local currency is the functional currency, and therefore
translation gains or losses associated with foreign-denominated monetary
accounts are accumulated in a separate section of shareholders' equity. For our
other international subsidiaries, the U.S. dollar is the functional currency,
and therefore local currency transaction gains and losses, arising from
remeasurement of payables and receivables denominated in local currency, are
included in our consolidated statements of income.

STOCK-BASED COMPENSATION

     We account for stock-based compensation using the intrinsic value method
prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees."
Accordingly, compensation expense for stock options is measured as the excess,
if any, of the quoted market price of Nabors common shares at the date of grant
over the amount an employee must pay to acquire the common shares. We grant
options at prices equal to the market price of our shares on the date of grant
and therefore do not record compensation expense related to these grants. SFAS
No. 148, "Accounting for Stock-Based Compensation - an Amendment to FAS 123,"
requires companies that continue to account for stock-based compensation in
accordance with APB 25 to disclose certain information using a tabular
presentation. The table presented below illustrates the effect on our net income
and earnings per share as if we had applied the fair value recognition
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to our
stock-based employee compensation. Under the provisions of SFAS 123,
compensation cost for stock-based compensation is determined based on fair
values as of the dates of grant estimated using an option pricing model such as
the Black-Scholes option-pricing model, and compensation cost is amortized over
the applicable option vesting period.

<Table>
<Caption>
                                                                             YEAR ENDED DECEMBER 31,
                                                                     ---------------------------------------
(In thousands, except per share amounts)                                 2003          2002          2001
<S>                                                                  <C>           <C>           <C>
Net income, as reported                                               $   192,228   $   121,489   $   357,450
Deduct: Total stock-based employee compensation expense determined
  under fair value method for all awards, net of related tax effects      (13,565)      (31,047)       (8,350)
                                                                      -----------   -----------   -----------

Pro forma net income                                                  $   178,663   $    90,442   $   349,100
Earnings per share:
  Basic - as reported                                                 $      1.31   $       .85   $      2.48
                                                                      -----------   -----------   -----------
  Basic - pro forma                                                   $      1.22   $       .63   $      2.42
                                                                      -----------   -----------   -----------
  Diluted - as reported                                               $      1.25   $       .81   $      2.24
                                                                      -----------   -----------   -----------
  Diluted - pro forma                                                 $      1.16   $       .60   $      2.19
                                                                      -----------   -----------   -----------
</Table>


     The pro forma amounts above were estimated using the Black-Scholes
option-pricing model with the following weighted-average assumptions for grants
during 2003, 2002 and 2001, respectively: risk-free interest rates of 2.23%,
3.79% and 4.74%; volatility of 47.58%, 48.19% and 50.42%; dividend yield of 0.0%
for all periods; and expected life of 3.5 years for all periods.

USE OF ESTIMATES

     The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America (GAAP) requires
management to make certain estimates and assumptions. These estimates and
assumptions affect the reported amounts of assets and liabilities, the
disclosures of contingent assets and liabilities at the balance sheet date and
the amounts of revenues and expenses recognized during the reporting period.
Actual results could differ from such estimates. Areas where critical accounting
estimates are made by management include:

o    depreciation and amortization of property, plant and equipment and
     intangible assets

o    impairment of property, plant and equipment

o    income taxes

o    allowance for doubtful accounts

o    litigation and insurance reserves

o    fair value of assets acquired and liabilities assumed

o    cash flow estimates

o    stock-based compensation



<PAGE>


RECENT ACCOUNTING PRONOUNCEMENTS

     In November 2002 the Financial Accounting Standards Board (FASB) issued
Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure
Requirements, Including Guarantees of Indebtedness of Others." FIN 45 requires
that upon issuance of certain types of guarantees, a guarantor recognize
and account for the fair value of the guarantee as a liability. FIN 45 contains
exclusions to this requirement, including the exclusion of a parent's guarantee
of its subsidiaries' debt to third parties. The initial recognition and
measurement provisions of FIN 45 have been applied on a prospective basis for
guarantees issued or modified after December 31, 2002. During 2003 we issued new
standby letters of credit which serve as guarantees under the provisions of FIN
45. The application of the recognition and measurement provisions of FIN 45 to
these guarantees was insignificant. The disclosure requirements of FIN 45 are
effective for financial statements of both interim and annual periods ending
after December 15, 2002 and are included in Note 13.

     In January 2003 the FASB issued Interpretation No. 46 (FIN 46),
"Consolidation of Variable Interest Entities," which addresses the consolidation
of variable interest entities (VIEs) by business enterprises that are the
primary beneficiaries. A VIE is an entity that does not have sufficient equity
investment at risk to permit it to finance its activities without additional
subordinated financial support, or whose equity investors lack the
characteristics of a controlling financial interest. The primary beneficiary of
a VIE is the enterprise that has the majority of the risks or rewards associated
with the VIE. In December 2003 the FASB issued a revision to FIN 46,
Interpretation No. 46R (FIN 46R), to clarify some of the provisions of FIN 46,
and to exempt certain entities from its requirements. Application of FIN 46R is
required in financial statements of public entities that have interests in
structures that are commonly referred to as special-purpose entities for periods
ending after December 15, 2003. Application for all other types of VIEs is
required in financial statements for periods ending after March 15, 2004. We
have no interests in structures that are commonly referred to as special-purpose
entities and therefore have not adopted FIN 46R as of December 31, 2003. We do
not expect our adoption of FIN 46R to materially affect our financial position,
results of operations or cash flows.

     In May 2003 the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS 149 amends and clarifies
financial accounting and reporting for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities under SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." SFAS 149 is effective in relation to certain issues for
fiscal quarters that began prior to June 15, 2003 and for certain contracts
entered into after June 30, 2003. The adoption of SFAS 149 had no impact on our
financial position, results of operations or cash flows as of and for the
year ended December 31, 2003.

     In May 2003 the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." SFAS 150
establishes standards for how an issuer classifies and measures in its statement
of financial position certain financial instruments with characteristics of
both liabilities and equity. In accordance with the standard, financial
instruments that embody obligations for the issuer are required to be
classified as liabilities. SFAS 150 is effective for such financial instruments,
except for those that apply to mandatorily redeemable noncontrolling interests,
entered into or modified after May 31, 2003, and otherwise was effective for
such financial instruments, except for those that apply to mandatorily
redeemable noncontrolling interests, at the beginning of the third quarter of
2003. The adoption of SFAS 150 had no initial impact on our financial position,
results of operations or cash flows as of and for the year ended December 31,
2003.

     In December 2003 the FASB issued SFAS No. 132 (revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits," that replaces
existing FASB disclosure requirements for pensions. The revised SFAS 132 is
effective for fiscal years ending after December 15, 2003, and for quarters
beginning after December 15, 2003. The disclosures related to our pension plan
included in Note 11 include all relevant disclosures required by the revised
SFAS 132.



                                   nbr (80-81)


<PAGE>


3 ACQUISITIONS

     On August 12, 2002, Nabors entered into an arrangement agreement to acquire
Ryan Energy Technologies, Inc., a corporation incorporated under the laws of
Alberta, Canada. Nabors' acquisition of Ryan was completed on October 9, 2002,
and became effective pursuant to a plan of arrangement approved by
the securityholders of Ryan and the Court of Queen's Bench of Alberta.

     Pursuant to the arrangement, Nabors Exchangeco (Canada) Inc., an indirect
wholly-owned Canadian subsidiary of Nabors, acquired all of the issued and
outstanding common shares of Ryan in exchange for approximately Cdn. $22.6
million (U.S. $14.2 million) in cash and 380,264 exchangeable shares of Nabors
Exchangeco, of which 219,493 exchangeable shares were immediately exchanged for
common shares of Nabors in accordance with the instructions of the holders of
those shares. The Nabors Exchangeco shares are exchangeable for Nabors common
shares, at each holder's option, on a one-for-one basis and are listed on the
Toronto Stock Exchange. Additionally, these exchangeable shares have essentially
identical rights as Nabors common shares, including but not limited to voting
rights and the right to receive dividends, if any, and will be automatically
exchanged upon the occurrence of certain events. The value of the Nabors
Exchangeco shares issued totaled Cdn. $18.5 million (U.S. $11.6 million). In
addition, we assumed Ryan debt totaling Cdn. $14.5 million (U.S. $9.1 million).
Ryan's results of operations were consolidated into ours commencing on October
9, 2002. The Ryan purchase price was allocated based on estimates of the fair
market value of assets acquired and liabilities assumed as of the acquisition
date and resulted in goodwill of approximately Cdn. $7.2 million (U.S. $4.8
million). Ryan manufactures and sells directional drilling and rig
instrumentation systems and provides directional drilling, rig instrumentation
and data collection services to oil and gas exploration and service companies
in the United States, Canada and Venezuela.

     On March 18, 2002, we acquired, for cash, 20.5% of the issued and
outstanding shares of Enserco Energy Service Company Inc., a Canadian
publicly-held corporation, for Cdn. $15.50 per share for a total price of Cdn.
$83.2 million (U.S. $52.6 million). On April 26, 2002, Nabors Exchangeco
acquired all of the remaining issued and outstanding common shares of Enserco in
exchange for approximately Cdn. $100.1 million (U.S. $64.1 million) in cash and
3,549,082 exchangeable shares of Nabors Exchangeco, of which 2,638,526
exchangeable shares were immediately exchanged for Nabors Industries, Inc.
(Nabors Delaware) common stock in accordance with the instructions of the
holders of those shares (which common stock was converted into our common shares
pursuant to our corporate reorganization on June 24, 2002). The value of the
Nabors Exchangeco shares issued totaled Cdn. $254.2 million (U.S. $162.8
million). In addition, we assumed Enserco debt totaling Cdn. $33.4 million (U.S.
$21.4 million). Enserco's results of operations were consolidated into ours
commencing on April 26, 2002. The Enserco purchase price was allocated based on
estimates of the fair market value of assets acquired and liabilities assumed as
of the acquisition date and resulted in goodwill of approximately Cdn. $164.7
million (U.S. $105.2 million). Enserco provided land drilling, well-servicing
and workover services in Canada and operated a fleet of 193 well-servicing rigs
and 30 drilling rigs as of our acquisition date.

     On November 13, 2001, we completed our acquisition of Command Drilling
Corporation in which we purchased all of Command's common stock at $3.35 per
share for a total purchase price of Cdn. $102.3 million (U.S. $65.1 million).
Command owned 15 rigs operating in the Canadian Rockies. The Command purchase
price was allocated based on estimates of the fair market value of assets
acquired and liabilities assumed as of the acquisition date and resulted in
goodwill of approximately Cdn. $15.3 million (U.S. $9.7 million).



<PAGE>


4 CASH AND CASH EQUIVALENTS AND MARKETABLE SECURITIES

     Our cash and cash equivalents, short-term and long-term marketable
securities consist of the following:

<Table>
<Caption>
                                                       DECEMBER 31,
                                 --------------------------------------------------------
(IN THOUSANDS)                                            2003
                                                    GROSS UNREALIZED     GROSS UNREALIZED
                                   FAIR VALUE         HOLDING GAINS       HOLDING LOSSES
<S>                              <C>                <C>                  <C>
Cash and cash equivalents        $       579,737     $            --      $            --
                                 ---------------     ---------------      ---------------
Marketable
  equity securities:
   Trading                                    --                  --                   --
   Available-for-sale                     48,843               9,379               (2,016)
                                 ---------------     ---------------      ---------------
Total marketable
  equity securities                       48,843               9,379               (2,016)
                                 ---------------     ---------------      ---------------
Marketable
  debt securities:
   Commercial paper
    and CDs                               50,743                  --                   --
   Corporate debt securities             319,327               2,392                   --
   U.S. Government
    debt securities                        7,103                  --                   --
   Government agencies
    debt securities                      285,358                  --                 (677)
   Mortgage-backed
    debt securities                          119                  --                   --
   Mortgage-CMO
    debt securities                       29,275                  31                   --
   Asset-backed
    debt securities                      211,585                 767                   --
                                 ---------------     ---------------      ---------------
Total marketable
  debt securities                        903,510               3,190                 (677)
                                 ---------------     ---------------      ---------------
                                 $     1,532,090     $        12,569      $        (2,693)
                                 ---------------     ---------------      ---------------
</Table>


<Table>
<Caption>
                                                       DECEMBER 31,
                                 --------------------------------------------------------
(IN THOUSANDS)                                            2002
                                                    GROSS UNREALIZED     GROSS UNREALIZED
                                   FAIR VALUE         HOLDING GAINS       HOLDING LOSSES
<S>                              <C>                <C>                  <C>

Cash and cash equivalents        $       414,051     $            --      $            --
                                 ---------------     ---------------      ---------------
Marketable
  equity securities:
   Trading                                 4,260               1,138                   --
   Available-for-sale                     45,574               4,733               (2,844)
                                 ---------------     ---------------      ---------------
Total marketable
  equity securities                       49,834               5,871               (2,844)
                                 ---------------     ---------------      ---------------
Marketable
  debt securities:
   Commercial paper
    and CDs                               76,548                  57                   --
   Corporate debt securities             204,084               4,063                   --
   U.S. Government
    debt securities                       42,675                 401                   --
   Government agencies
    debt securities                      386,096               1,564                   --
   Foreign government
    debt securities                       15,213                 121                   --
   Mortgage-backed
    debt securities                          355                   5                   --
   Asset-backed
    debt securities                      141,943               1,710                   --
                                 ---------------     ---------------      ---------------
Total marketable
  debt securities                        866,914               7,921                   --
                                 ---------------     ---------------      ---------------
                                 $     1,330,799     $        13,792      $        (2,844)
                                 ---------------     ---------------      ---------------
</Table>


     The estimated fair values of our marketable debt securities as of December
31, 2003, by contractual maturity, are shown below. Expected maturities will
differ from contractual maturities because the issuers of the securities may
have the right to repay obligations without prepayment penalties and we may
elect to sell the securities prior to the maturity date.

<Table>
<Caption>
                                            ESTIMATED
                                           FAIR VALUE
                                          ------------
(IN THOUSANDS)                                2003
<S>                                       <C>
Marketable debt securities:
  Due in one year or less                 $    291,093
  Due after one year through five years        612,417
                                          ------------
                                          $    903,510
                                          ------------
</Table>



                                  nbr (82-83)


<PAGE>


     Certain information regarding our marketable debt and equity securities is
presented below:

<Table>
<Caption>
                                          YEAR ENDED DECEMBER 31,
                              ----------------------------------------------
(IN THOUSANDS)                    2003             2002             2001
<S>                           <C>              <C>              <C>
Available-for-sale:
  Proceeds from sales
   and maturities                1,393,638          542,133          431,498
  Realized gains,
   net of realized losses            3,417            2,310              200
                              ------------     ------------     ------------
</Table>


5 PROPERTY, PLANT AND EQUIPMENT

     The major components of our property, plant and equipment are as follows:

<Table>
<Caption>
                                                                    DECEMBER 31,
                                                            ----------------------------
(IN THOUSANDS)                                                  2003             2002
<S>                                                         <C>              <C>
Land                                                        $    12,037      $    15,203
Buildings                                                        26,703           30,177
Drilling, workover and
  well-servicing
  rigs, and related equipment                                 3,637,296        3,307,504
Marine transportation and
  supply vessels                                                159,530          156,212
Oilfield hauling and mobile                                     143,279           96,540
  equipment
Other machinery and equipment                                    33,358           31,319
Net profits interests in oil and
  gas properties                                                 84,807           35,881
                                                            -----------      -----------
                                                              4,097,010        3,672,836
Less: accumulated depreciation
     and amortization                                        (1,081,826)        (855,905)
     accumulated depletion on
     oil and gas properties                                     (24,392)         (15,864)
                                                            -----------      -----------

                                                            $ 2,990,792      $ 2,801,067
                                                            -----------      -----------
</Table>


     Repair and maintenance expense included in direct costs in our consolidated
statements of income totaled $195.7 million, $138.5 million and $223.8 million
for the years ended December 31, 2003, 2002 and 2001, respectively.

     Interest costs of $.9 million, $1.1 million and $1.6 million were
capitalized during the years ended December 31, 2003, 2002 and 2001,
respectively.

     Certain of our marine vessels have been leased under a bareboat charter
arrangement to Sea Mar Management LLC (Notes 12 and 13). Future minimum payments
due to us under this arrangement are as follows:

<Table>
(IN THOUSANDS)
<S>            <C>
2004           $        29,618
2005                    29,537
2006                    29,537
2007                    12,705
2008                        --
Thereafter                  --
               ---------------
               $       101,397
               ---------------
</Table>


     Payments received under this bareboat charter arrangement amounted to $29.5
million and $18.0 million in 2003 and 2002, respectively.

6 INVESTMENTS IN UNCONSOLIDATED AFFILIATES

     Our principal operations accounted for using the equity method include a
construction operation (40%) and a logistics operation (50%) in Alaska, drilling
and workover operations located in Saudi Arabia (50%), and a supply and marine
transportation operation in the Gulf of Mexico (25%). These unconsolidated
affiliates are integral to our operations in those locations. See Note 12 for
a discussion of transactions with these related parties.

     Combined condensed financial data for investments in unconsolidated
affiliates accounted for using the equity method of accounting is summarized as
follows:

<Table>
<Caption>
                                 DECEMBER 31,
                          -------------------------
(IN THOUSANDS)                2003           2002
<S>                       <C>            <C>
Current assets            $   78,020     $  104,265
Long-term assets             135,073        122,682
Current liabilities           48,312         63,366
Long-term liabilities         40,201         40,761
                          ----------     ----------
</Table>


<Table>
<Caption>
                                       YEAR ENDED DECEMBER 31,
                                ---------------------------------------
(IN THOUSANDS)                     2003           2002           2001
<S>                             <C>            <C>            <C>
Gross revenues                  $  312,008     $  334,000     $  285,505
Gross margin                        41,809         52,861         73,532
Net income                          21,689         29,400         51,421
Nabors' Earnings from
  unconsolidated affiliates         10,183         14,775         26,334
                                ----------     ----------     ----------
</Table>


     Cumulative undistributed earnings of our unconsolidated affiliates
included in retained earnings as of December 31, 2003 totaled approximately
$42.0 million.



<PAGE>


7 FINANCIAL INSTRUMENTS AND RISK CONCENTRATION

     We may be exposed to certain market risks arising from the use of financial
instruments in the ordinary course of business. This risk arises primarily as a
result of potential changes in the fair market value of financial instruments
that would result from adverse fluctuations in foreign currency exchange rates,
credit risk, interest rates and marketable security and non-marketable security
prices as discussed below.

FOREIGN CURRENCY RISK

     We operate in a number of international areas and are involved in
transactions denominated in currencies other than U.S. dollars, which exposes us
to foreign exchange rate risk. The most significant exposures arise in
connection with our operations in Canada and Saudi Arabia, which usually are
substantially unhedged. For our unconsolidated affiliate in Saudi Arabia, upon
renewal of our contracts, we have been converting Saudi riyal-denominated
contracts to U.S. dollar-denominated contracts in order to reduce our exposure
to the Saudi riyal, even though that currency has been pegged to the U.S. dollar
at a rate of 3.745 Saudi riyals to 1.00 U.S. dollar since 1986. We cannot
guarantee that we will be able to convert future Saudi riyal-denominated
contracts to U.S. dollar-denominated contracts or that the Saudi riyal exchange
rate will continue in effect as in the past.

     At various times, we utilize local currency borrowings (foreign
currency-denominated debt), the payment structure of customer contracts and
foreign exchange contracts to selectively hedge our exposure to exchange rate
fluctuations in connection with monetary assets, liabilities, cash flows and
commitments denominated in certain foreign currencies. A foreign exchange
contract is a foreign currency transaction, defined as an agreement to exchange
different currencies at a given future date and at a specified rate.

CREDIT RISK

     Our financial instruments that potentially subject us to concentrations of
credit risk consist primarily of cash equivalents, investments in marketable and
non-marketable securities, accounts receivable, and our interest rate swap and
range cap and floor transactions. Cash equivalents such as deposits and
temporary cash investments are held by major banks or investment firms. Our
investments in marketable and non-marketable securities are managed within
established guidelines which limit the amounts that may be invested with any one
issuer and which provide guidance as to issuer credit quality. We believe that
the credit risk in such instruments is minimal. In addition, our trade
receivables are with a variety of U.S., international and foreign-country
national oil and gas companies. Management considers this credit risk to be
limited due to the financial resources of these companies. We perform ongoing
credit evaluations of our customers and we generally do not require material
collateral. We maintain reserves for potential credit losses, and such losses
have been within management's expectations.

INTEREST RATE, AND MARKETABLE AND NON-MARKETABLE SECURITY PRICE RISK

     Our financial instruments that are potentially sensitive to changes in
interest rates include our $1.381 billion zero coupon convertible senior
debentures, our $700 million zero coupon exchangeable senior notes, our 6.8%,
4.875% and 5.375% senior notes, our interest rate swap and range cap and floor
transactions, our investments in debt securities (including corporate,
asset-backed, U.S. Government, Government agencies, foreign government,
mortgage-backed debt and mortgage-CMO debt securities) and our investments in
overseas funds investing primarily in a variety of public and private U.S. and
non-U.S. securities (including asset-backed securities and mortgage-backed
securities, global structured asset securitizations, whole loan mortgages, and
participations in whole loans and whole loan mortgages), which are classified as
non-marketable securities.

     We may utilize derivative financial instruments that are intended to manage
our exposure to interest rate risks. The use of derivative financial instruments
could expose us to further credit risk and market risk. Credit risk in this
context is the failure of a counterparty to perform under the terms of the
derivative contract. When the fair value of a derivative contract is positive,
the counterparty would owe us, which can create credit risk for us. When the
fair value of a derivative contract is negative, we would owe the counterparty,
and therefore, we would not be exposed to credit risk. We attempt to minimize
credit risk in derivative instruments by entering into transactions with major
financial institutions that have a significant asset base. Market risk related
to derivatives is the adverse effect to the value of a financial instrument that
results from changes in interest rates. We try to manage market risk associated
with interest-rate contracts by establishing and monitoring parameters that
limit the type and degree of market risk that we undertake.



                                   nbr (84-85)


<PAGE>


     Our $700 million zero coupon senior exchangeable notes include a contingent
interest provision, discussed in Note 8 below, which qualifies as an embedded
derivative under SFAS 133, as amended by SFAS 149. This embedded derivative is
required to be separated from the notes and valued at its fair value at the
inception of the note indenture. Any subsequent change in fair value of this
embedded derivative will be recorded in our consolidated statements of income.
The fair value of the contingent interest provision at inception of the note
indenture was nominal. In addition, there was no significant change in the fair
value of this embedded derivative through December 31, 2003, resulting in no
impact on our consolidated statement of income for the year ended December 31,
2003.

     On October 21, 2002, we entered into an interest rate swap transaction with
a third-party financial institution to hedge our exposure to changes in the
fair value of $200 million of our fixed rate 5.375% senior notes due 2012, which
has been designated as a fair value hedge under SFAS 133, as amended by SFAS
149. Additionally, on October 21, 2002, we purchased a LIBOR range cap and sold
a LIBOR floor, in the form of a cashless collar, with the same third-party
financial institution with the intention of mitigating and managing our
exposure to changes in the three-month U.S. dollar LIBOR rate. This transaction
does not qualify for hedge accounting treatment under SFAS 133, as amended by
SFAS 149, and any change in the cumulative fair value of this transaction will
be reflected as a gain or loss in our consolidated statements of income.

     During the years ended December 31, 2003 and 2002, we recorded interest
savings related to our interest rate swap agreement accounted for as a fair
value hedge of $6.8 million and $1.2 million, respectively, which served to
reduce interest expense. The fair value of our interest rate swap agreement is
recorded as a derivative asset, included in other long-term assets, and totaled
approximately $4.2 million and $10.1 million as of December 31, 2003 and 2002,
respectively. The carrying value of our 5.375% senior notes has been increased
by the same amount as of December 31, 2003 and 2002.

     The fair value of our range cap and floor transaction is recorded as a
derivative liability, included in other long-term liabilities, and totaled
approximately $3.7 million and $3.8 million as of December 31, 2003 and 2002,
respectively. We recorded losses of approximately $1.1 million and $3.8 million
for the years ended December 31, 2003 and 2002, respectively, related to this
derivative instrument; such amounts are included in other income in our
consolidated statements of income. The loss in the current year is comprised of
the recognition of approximately $1.2 million of expense in 2003 related to the
settlement of amounts due to the counterparty on our range cap and floor
derivative instrument discussed below, which were partially offset by a gain of
approximately $.1 million resulting from the change in cumulative fair value of
this derivative instrument during 2003. As a result of the three-month U.S.
dollar LIBOR rate being below our 2.665% floor on August 15, 2003 (such rate was
1.13%), we paid approximately $.8 million to the counterparty on November 15,
2003 as settlement for the three-month period from August 15 to November 15,
2003. As a result of the three-month U.S. Dollar LIBOR rate being below our
2.665% floor on November 15, 2003 (such rate was 1.18%), we are obligated to
pay, on February 15, 2004, approximately $.8 million to the counterparty as
settlement for amounts due for the three-month period from November 15, 2003 to
February 15, 2004. We recorded the payment of approximately $.8 million made on
November 15, 2003 and approximately $.4 million of the obligation due on
February 15, 2004 as expense in other income in 2003 and will record the
remaining amount of approximately $.4 million due on February 15, 2004 in the
first quarter of 2004.

     On July 25, 2002, we entered into an interest rate hedge transaction with a
third-party financial institution to manage and mitigate interest rate risk
exposure relative to our August 2002 debt financing. Under the agreement, we
agreed to receive (pay) cash from (to) the counterparty based on the difference
between 4.43% and the ten-year Treasury rate on August 23, 2002, assuming a
$100.0 million notional amount



<PAGE>


with semi-annual interest payments over a ten-year maturity. We accounted for
this transaction as a cash flow hedge. During August 2002 we paid approximately
$1.5 million related to the termination of this agreement. This payment was
recorded as a reduction to accumulated other comprehensive income in our
consolidated balance sheet and will be amortized into earnings as additional
interest expense, using the effective interest method, over the term of the
5.375% senior notes due 2012 as discussed in Note 8 below.

     On March 26, 2002, in anticipation of closing the Enserco acquisition
discussed in Note 3, we entered into two foreign exchange contracts with a total
notional value of Cdn. $115.9 million and maturity dates of April 29, 2002.
Additionally, on April 9, 2002, we entered into a third foreign exchange
contract with a notional value of Cdn. $50.0 million maturing April 29, 2002.
The notional amounts of these contracts were used to fund the cash portion of
the Enserco acquisition purchase price. The notional amounts of these contracts
represented the amount of foreign currency purchased at maturity and did not
represent our exposure under these contracts. Although such contracts served as
an economic hedge against our foreign currency risk related to the cash portion
of the acquisition cost, these contracts did not qualify for hedge accounting
treatment under SFAS 133, as amended by SFAS 149. We recognized a gain on these
foreign exchange contracts of approximately U.S. $1.78 million included in other
income in our consolidated statement of income for the year ended December 31,
2002.

FAIR VALUE OF FINANCIAL INSTRUMENTS

     The fair value of our long-term debt is estimated based on quoted market
prices or prices quoted from third-party financial institutions. The carrying
and fair values of our long-term debt, including the current portion, are as
follows:

<Table>
<Caption>
                                                                                         DECEMBER 31,
                                                             -------------------------------------------------------------------
(IN THOUSANDS)                                                             2003                                2002
                                                             CARRYING VALUE      FAIR VALUE      CARRYING VALUE      FAIR VALUE
<S>                                                          <C>                <C>              <C>                <C>
4.875% senior notes due August 2009                           $    223,499      $    234,585      $    223,234      $    231,854
5.375% senior notes due August 2012                                277,248(1)        290,813(1)        282,901(1)        293,478(1)
$700 million zero coupon senior exchangeable notes due
  June 2023                                                        700,000           643,651                --                --
$825 million zero coupon convertible senior debentures due
  June 2020                                                             --                --           489,126           494,081
$1.381 billion zero coupon convertible senior debentures
  due February 2021                                                784,807           780,880           765,549           756,733
6.8% senior notes due April 2004                                   295,267           299,681           295,237           310,068
Other long-term debt                                                 4,117             4,117             9,101             9,101
8.625% senior subordinated notes due April 2008                         --                --            42,493            43,930
                                                              ------------      ------------      ------------      ------------
                                                              $  2,284,938      $  2,253,727      $  2,107,641      $  2,139,245
                                                              ------------      ------------      ------------      ------------
</Table>


(1)  The amounts presented for the years ended December 31,2003 and 2002 include
     $4.2 million and $10.1 million, respectively, related to the fair value of
     the interest rate swap executed on October 21,2002.


     The fair values of our cash equivalents, trade receivables and trade
payables approximate their carrying values due to the short-term nature of
these instruments.

     We maintain an investment portfolio of marketable and non-marketable debt
and equity securities that exposes us to price risk (Note 4). The marketable and
non-marketable securities are carried at fair market value and include $952.4
million in securities classified as available-for-sale as of December 31, 2003.
We had no securities classified as trading as of December 31, 2003.



                                   nbr (86-87)


<PAGE>
8 DEBT

     Long-term debt consists of the following:

<Table>
<Caption>
                                               DECEMBER 31,
                                       ----------------------------
(IN THOUSANDS)                             2003             2002
<S>                                    <C>               <C>
4.875% senior notes
  due August 2009                      $  223,499        $  223,234
5.375% senior notes
  due August 2012                         277,248(1)        282,901(1)
$700 million zero coupon senior
  exchangeable notes due June 2023        700,000                --
$825 million zero coupon
  convertible senior debentures
  due June 2020                                --           489,126
$1.381 billion zero coupon
  convertible senior debentures
  due February 2021                       784,807           765,549
6.8% senior notes due April 2004          295,267           295,237
Other long-term debt                        4,117             9,101
8.625% senior subordinated
  notes due April 2008                         --            42,493
                                       ----------        ----------
                                        2,284,938         2,107,641
Less: current portion                     299,385           492,985
                                       ----------        ----------
                                       $1,985,553        $1,614,656
                                       ----------        ----------
</Table>


(1)  The amounts presented for the years ended December 31,2003 and 2002 include
     $4.2 million and $10.1 million, respectively, related to the fair value of
     the interest rate swap executed on October 21,2002 (Note 7).

     The carrying amount of our $1.381 billion zero coupon convertible senior
debentures, 4.875% senior notes and 5.375% senior notes as of December 31, 2003,
included in the table above, are net of unamortized discounts of approximately
$415.4 million, $1.5 million and $1.9 million, respectively.

     On June 10, 2003, Nabors Delaware, our wholly-owned subsidiary, completed a
private placement of $700 million aggregate principal amount of zero coupon
senior exchangeable notes due 2023 that are fully and unconditionally guaranteed
by us. The notes were reoffered by the initial purchaser of the notes to
qualified institutional buyers under Rule 144A of the Securities Act of 1933, as
amended, and outside the United States in accordance with Regulation S under the
Securities Act. Nabors and Nabors Delaware filed a registration statement on
Form S-3 pursuant to the Securities Act with respect to the notes on August 8,
2003. The notes do not bear interest, do not accrete and have a zero yield to
maturity, unless Nabors Delaware becomes obligated to pay contingent interest as
defined in the note indenture and described below.

     The notes are exchangeable at the option of the holders into 14.2653 common
shares of Nabors per $1,000 principal amount of notes (subject to adjustment for
certain events) if any of the following circumstances occur: (1) if in any
calendar quarter beginning after the quarter ending September 30, 2003, the
closing sale price per share of Nabors' common shares for at least 20 trading
days during the period of 30 consecutive trading days ending on the last trading
day of the previous calendar quarter is greater than or equal to 120%, or with
respect to all calendar quarters beginning on or after July 1, 2008, 110%, of
the applicable exchange price per share of the Nabors' common shares on such
last trading day (the initial exchange price per share is $70.10 and is subject
to adjustment for certain events detailed in the note indenture; 120% of this
initial price per share is $84.12 and 110% of this initial price per share is
$77.11), (2) subject to certain exceptions, during the five business day period
after any ten consecutive trading day period in which the trading price per
$1,000 principal amount of notes for each day of such ten trading day period was
less than 95% of the product of the closing sale price of Nabors' common shares
and the exchange rate of such note, (3) if Nabors Delaware calls the notes for
redemption, or (4) upon the occurrence of specified corporate transactions
described in the note indenture.

     The notes are unsecured and are effectively junior in right of payment to
any of Nabors Delaware's future secured debt. The notes will rank equally with
any of Nabors Delaware's other existing and future unsecured and unsubordinated
debt and will be senior in right of payment to any of Nabors Delaware's
subordinated debt. The guarantee of Nabors will be similarly unsecured and have
a similar ranking to the notes so guaranteed. Holders of the notes have the
right to require Nabors Delaware to repurchase the notes at a purchase price
equal to 100% of the principal amount of the notes plus contingent interest and
additional amounts, if any, on June 15, 2008, June 15, 2013 and June 15, 2018 or
upon a fundamental change as described in the note indenture. If Nabors Delaware
is required to repurchase the notes, Nabors Delaware will have the right to
deliver, in lieu of cash, our common shares or a combination of cash and common
shares. If Nabors Delaware elects to pay all or a portion of the purchase price
in our common shares, the number of common shares we will issue will be equal to
the purchase price divided by the market price of our common shares. For these
purposes, the market price means the average of the sale prices of our common
shares for the five trading day period ending on the third business day prior to
the applicable purchase date. We do not presently anticipate using shares to
satisfy any such future purchase obligations.
<PAGE>


     Nabors Delaware will be obligated to pay contingent interest during any
six-month period from June 15 to December 14 or from December 15 to June 14
commencing on or after June 15, 2008 for which the average trading price of the
notes for each day of the applicable five trading day reference period equals or
exceeds 120% of the principal amount of the notes as of the day immediately
preceding the first day of the applicable six-month interest period. The amount
of contingent interest payable per note in respect to any six-month period will
equal 0.185% of the principal amount of a note. The five day trading reference
period means the five trading days ending on the second trading day immediately
preceding the relevant six-month interest period.

     We used a portion of the net proceeds from the issuance of the notes to
redeem the remaining outstanding principal amount of Nabors Delaware's $825
million zero coupon convertible senior debentures due 2020 on June 20, 2003 and
our associated guarantees. The redemption price was $655.50 per $1,000 principal
amount of the debentures for an aggregate redemption price paid of approximately
$494.9 million. The redemption of the debentures did not result in any gain or
loss as the debentures were redeemed at prices equal to their carrying value on
June 20, 2003. The remainder of the proceeds of the notes were invested in cash
and marketable securities.

     On April 1, 2003, we redeemed our 8.625% senior subordinated notes due
April 2008 and all associated guarantees at a redemption price of $1,043.13 per
$1,000 principal amount of the notes together with accrued and unpaid interest
to the date of redemption. The aggregate redemption price was $45.2 million and
resulted in the recognition of a pretax loss of approximately $.9 million,
resulting from the redemption of the notes at prices higher than their carrying
value on April 1, 2003. This loss was recorded in other income in our
consolidated statements of income during 2003.

     During 2002 we purchased $.6 million face value of our 8.625% senior
subordinated notes due April 2008 in the open market at a price of 108%. In
addition, we purchased $4.7 million face value of our 6.8% senior notes due
April 2004 in the open market at a price of 104%. Upon settlement of these
transactions, we paid $5.7 million and recognized a pretax loss of approximately
$.2 million, resulting from the repurchases of these notes at prices higher than
their carrying value. Additionally, we repaid Cdn. $12.9 million (U.S. $8.3
million) and Cdn. $22.3 million (U.S. $14.3 million) of the debt assumed in the
Ryan and Enserco acquisitions, respectively. We also made a $2.5 million
scheduled principal payment relating to certain of our medium-term notes.

     On August 22, 2002, Nabors Holdings 1, ULC, one of our indirect,
wholly-owned subsidiaries, issued $225 million aggregate principal amount of
4.875% senior notes due 2009 that are fully and unconditionally guaranteed by
Nabors and Nabors Delaware. Concurrently with this offering by Nabors Holdings,
Nabors Delaware issued $275 million aggregate principal amount of 5.375% senior
notes due 2012, which are fully and unconditionally guaranteed by Nabors. Both
issues of senior notes were resold by a placement agent to qualified
institutional buyers under Rule 144A of the Securities Act of 1933, as amended.
Interest on each issue of senior notes is payable semi-annually on February 15
and August 15 of each year, beginning on February 15, 2003.

     Both issues are unsecured and are effectively junior in right of payment to
any of their respective issuers' future secured debt. The senior notes will rank
equally in right of payment with any of their respective issuers' future
unsubordinated debt and will be senior in right of payment to any of such
issuers' subordinated debt. The guarantees of Nabors Delaware and Nabors with
respect to the senior notes issued by Nabors Holdings, and the guarantee of
Nabors with respect to the senior notes issued by Nabors Delaware, are similarly
unsecured and have a similar ranking to the series of senior notes so
guaranteed.

     Subject to certain qualifications and limitations, the indentures governing
the senior notes issued by Nabors Holdings and Nabors Delaware limit the ability
of Nabors and its subsidiaries to incur liens and to enter into sale and
lease-back transactions. In addition, such indentures limit the ability of
Nabors, Nabors Delaware and Nabors Holdings to enter into mergers,
consolidations or transfers of all or substantially all of such entity's assets
unless the successor company assumes the obligations of such entity under the
applicable indenture.

     During February 2001 we completed a private placement of zero coupon
convertible senior debentures due 2021. The original aggregate principal amount
of the debentures at maturity totaled $1.381 billion. The debentures were issued
at a discount with net proceeds to Nabors, after expenses, totaling
approximately $828.0 million. Our $1.381 billion debentures can be put to us on
February 5, 2006, February 5, 2011 and February 5, 2016, for a purchase price
equal to the issue price plus accrued original issue discount to the date of
repurchase.



                                   nbr (88-89)



<PAGE>


     The original issue price of the debentures was $608.41 per $1,000 principal
amount at maturity. The yield to maturity of the debentures is 2.5% compounded
semi-annually with no periodic cash payments of interest. At the holder's
option, the $1.381 billion debentures can be converted, at any time prior to
maturity or their earlier redemption, into our common shares, at a conversion
rate of 7.0745 shares per $1,000 principal amount at maturity. The conversion
rate is subject to adjustment under formulae as set forth in the indenture (the
agreement governing the terms of the debt) in certain events, including: (1) the
issuance of Nabors common shares as a dividend or distribution on the common
shares; (2) certain subdivisions and combinations of the common shares; (3) the
issuance to all holders of common shares of certain rights or warrants to
purchase common shares; (4) the distribution of capital stock, other than Nabors
common shares to Nabors' shareholders, or evidences of Nabors' indebtedness or
of assets; and (5) distribution consisting of cash, excluding any quarterly cash
dividend on the common shares to the extent that the aggregate cash dividend per
share of common shares in any quarter does not exceed certain amounts. Instead
of delivering common shares upon conversion of any debentures, we may elect to
pay the holder cash for all or a portion of the debentures.

     We may elect to pay all or a portion of the purchase price of the
debentures in common shares instead of cash, depending upon our cash balances
and cash requirements at that time. We do not presently anticipate using common
shares to satisfy any such future purchase obligations. In accordance with the
indenture with respect to the debentures, we cannot redeem the $1.381 billion
debentures before February 5, 2006, after which time we may redeem all or a
portion of the debentures for cash at any time at their accreted value.

     During 2001 we entered into several private transactions with a
counterparty to purchase $70 million face value of our $825 million zero coupon
convertible senior debentures due 2020 at an average price of $606.07 for each
$1,000 face amount of debentures and $181 million face value of our $1.381
billion debentures at an average price of $528.30 for each $1,000 face amount of
debentures. Upon settlement of these transactions in December 2001 we paid
$139.8 million to the counterparty and recognized a pretax gain of $15.3 million
resulting from the repayment of the debentures at prices lower than
their carrying value. The gain was recorded as other income in our consolidated
statements of income.

     As of December 31, 2003, the maturities of our long-term debt for each of
the five years after 2003 and thereafter are as follows:

<Table>
<Caption>
                        ASSUMING ZERO COUPON
                     CONVERTIBLE DEBENTURES ARE
               --------------------------------------
(IN THOUSANDS)     PAID AT                PAID AT
                   MATURITY           FIRST PUT DATE
<S>            <C>                    <C>
2004           $       299,392        $       299,392
2005                        --                     --
2006                        --                826,800(1)
2007                        --                     --
2008                        --                700,000(2)
Thereafter           2,400,200(3)             500,000
               ---------------        ---------------
               $     2,699,592        $     2,326,192
               ---------------        ---------------
</Table>


(1)  Represents our $1.381 billion zero coupon convertible senior debentures due
     2021 which can be put to us on February 5,2006.

(2)  Represents our $700 million zero coupon senior exchangeable notes due 2023
     which can be put to us on June 15, 2008.

(3)  Includes $1.2 billion, representing the portion of our $1.381 billion zero
     coupon convertible senior debentures due 2021 that have not been
     redeemed, $700 million of our zero coupon senior exchangeable notes due
     2023, and $225 million and $275 million of our senior notes due 2009 and
     2012, respectively.

     We have three letter of credit facilities and a Canadian line of credit
facility with various banks as of December 31, 2003. We did not have any
short-term borrowings outstanding at December 31, 2003 and 2002. Availability
and borrowings under our credit facilities are as follows:

<Table>
<Caption>
                                        DECEMBER 31,
                                  --------------------------
(IN THOUSANDS)                        2003           2002
<S>                               <C>             <C>
Credit available                  $   96,825      $   79,745
Letters of credit outstanding        (56,288)        (56,267)
                                  ----------      ----------
Remaining availability            $   40,537      $   23,478
                                  ----------      ----------
</Table>



<PAGE>
9 INCOME TAXES

     Income (loss) before income taxes was comprised of the following:

<Table>
<Caption>
                           YEAR ENDED DECEMBER 31,
                   -----------------------------------------
(IN THOUSANDS)        2003             2002           2001
<S>                <C>             <C>             <C>
United States      $ (192,405)     $  (28,157)     $ 461,042
Foreign               367,028         168,931         96,570
                   ----------      ----------     ----------
Income before
  income taxes     $  174,623      $  140,774     $  557,612
                   ----------      ----------     ----------
</Table>

     Income taxes have been provided based upon the tax laws and rates in the
countries in which operations are conducted and income is earned. We are a
Bermuda-exempt company. Bermuda does not impose corporate income taxes. Our U.S.
subsidiaries are subject to a U.S. federal tax rate of 35%.


     Income tax (benefit) expense consisted of the following:

<Table>
<Caption>
                                          YEAR ENDED DECEMBER 31,
                                 -----------------------------------------
(IN THOUSANDS)                       2003           2002           2001
<S>                              <C>             <C>            <C>
Current:
  U.S. federal                   $    9,085      $    4,458     $   60,783
  Foreign                              (680)          5,113         17,078
  State                                  89             614          5,857
                                 ----------      ----------     ----------
                                      8,494          10,185         83,718
                                 ----------      ----------     ----------
Deferred:
  U.S. federal                      (53,121)          4,669        114,935
  Foreign                            29,051           2,274         (1,091)
  State                              (2,029)          2,157          2,600
                                 ----------      ----------     ----------
                                    (26,099)          9,100        116,444
                                 ----------      ----------     ----------
Income tax (benefit) expense     $  (17,605)     $   19,285     $  200,162
                                 ----------      ----------     ----------
</Table>

     Nabors is not subject to tax in Bermuda. A reconciliation of the
differences between taxes on income before income taxes computed at the
appropriate statutory rate and our reported provision for income taxes follows:

<Table>
<Caption>
                                                                                         YEAR ENDED DECEMBER 31,
                                                                              -------------------------------------------
(IN THOUSANDS)                                                                   2003             2002            2001
<S>                                                                           <C>              <C>             <C>
Income tax provision at statutory rate
  (Bermuda rate of 0% in 2003 and 2002 and U.S. rate of 35% in 2001)          $       --       $       --      $  195,164
Taxes (benefit) on U.S. and foreign (losses) earnings at greater than the
  Bermuda rate                                                                   (17,281)          10,944              --
Increase in valuation allowance                                                    5,163            6,540              --
Taxes on foreign earnings at less than the Bermuda rate in 2003 and 2002
  and the U.S. rate in 2001 and other                                                 --               --            (805)
Effect of change in tax rate (Canada)                                             (4,226)              --              --
State income taxes (benefit)                                                      (1,261)           1,801           5,803
                                                                              ----------       ----------      ----------
Income tax (benefit) expense                                                  $  (17,605)      $   19,285      $  200,162
                                                                              ----------       ----------      ----------
Effective tax rate                                                                   (10)%             14%             36%
                                                                              ----------       ----------      ----------
</Table>

     In both 2002 and 2003 we provided a valuation allowance against net
operating loss carryforwards in various foreign tax jurisdictions based on our
consideration of existing temporary differences and expected future earnings
levels in those jurisdictions.

     The significant components of our deferred tax assets and liabilities were
as follows:

<Table>
<Caption>
                                                               DECEMBER 31,
                                                        --------------------------
(IN THOUSANDS)                                              2003            2002
<S>                                                     <C>             <C>
Deferred tax assets:
  Net operating loss carryforwards                      $  239,291      $   85,012
  Tax credit carryforwards                                   5,796          22,871
  Accrued expenses not currently deductible and other       27,737          35,496
Less: valuation allowance                                  (11,703)         (6,540)
                                                        ----------      ----------
    Deferred tax assets, net of valuation allowance        261,121         136,839
                                                        ----------      ----------
Deferred tax liabilities:
  Depreciation for tax in excess of book expense          (594,589)       (478,231)
  Unrealized gain on marketable securities                  (2,914)         (3,316)
                                                        ----------      ----------
    Total deferred tax liabilities                        (597,503)       (481,547)
                                                        ----------      ----------
    Net deferred tax liabilities                          (336,382)       (344,708)
    Less: net current asset portion                         36,442          32,846
                                                        ----------      ----------
    Net long-term deferred tax liability                $ (372,824)     $ (377,554)
                                                        ----------      ----------
</Table>

                                   nbr (90-91)
<PAGE>
     In conjunction with our acquisitions of Enserco and Ryan in 2002, deferred
tax liabilities of $52.8 million and $4.2 million, respectively, were recorded
in the year of acquisition.

     For U.S. federal income tax purposes, we have net operating loss
carryforwards of approximately $671.9 million that, if not utilized, will expire
at various times from 2009 to 2023. The net operating loss carryforwards for
alternative minimum tax purposes are approximately $535.6 million. There are
alternative minimum tax credit carryforwards of $5.5 million available to offset
future regular tax liabilities.

     The NOL carryforwards subject to expiration expire as follows:

<Table>
<Caption>
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,     TOTAL      U.S. FEDERAL      FOREIGN
<S>                      <C>           <C>             <C>
2004                     $    6,246     $       --     $    6,246
2005                          5,152             --          5,152
2006                         14,876             --         14,876
2007                          3,082             --          3,082
2008                          4,162             --          4,162
2009                            779            779             --
2010                            482            482             --
2011                         11,598         11,598             --
2017                         38,751         38,751             --
2018                         23,119         23,119             --
2019                            737            737             --
2020                            737            737             --
2021                            738            738             --
2022                        225,842        225,842             --
2023                        369,107        369,107             --
Indefinite                   26,070             --         26,070
                         ----------     ----------     ----------
Total                    $  731,478     $  671,890     $   59,588
                         ----------     ----------     ----------
</Table>

     In addition, for state income tax purposes, we have net operating loss
carryforwards of approximately $415.8 million that, if not utilized, will expire
at various times from 2005 to 2023.

     Under U.S. federal tax law, the amount and availability of loss
carryforwards (and certain other tax attributes) are subject to a variety of
interpretations and restrictive tests applicable to Nabors and our subsidiaries.
The utilization of such carryforwards could be limited or effectively lost upon
certain changes in ownership. Accordingly, although we believe substantial loss
carryforwards are available to us, no assurance can be given concerning such
loss carryforwards, or whether or not such loss carryforwards will be available
in the future.

     In circumstances where our drilling rigs and other assets are operating in
certain foreign taxing jurisdictions, and it is expected that we will redeploy
such assets before they give rise to future tax consequences, we do not
recognize any deferred tax liabilities on the earnings from these assets.

10 COMMON SHARES AND STOCK OPTIONS

COMMON SHARES

     During 2003 warrants issued in conjunction with our acquisitions of Enserco
(April 2002) and New Prospect Drilling Company (May 1998) were exercised,
resulting in the issuance of 49,000 and 200,000 of our common shares,
respectively.

     In conjunction with our acquisition of Ryan in October 2002 and our
acquisition of Enserco in April 2002, we issued 380,264 and 3,549,082
exchangeable shares of Nabors Exchangeco, respectively, of which 219,493 and
2,638,526 exchangeable shares were immediately exchanged for our common shares,
respectively.

     The exchangeable shares of Nabors Exchangeco are exchangeable for Nabors
common shares on a one-for-one basis. The exchangeable shares are included in
capital in excess of par value.

     Subsequent to these acquisitions, during 2002, an additional 484,756
exchangeable shares were exchanged for our common shares leaving a total of
586,571 exchangeable shares outstanding as of December 31, 2002. During 2003
an additional 208,315 exchangeable shares were exchanged for our common shares
leaving a total of 378,256 exchangeable shares outstanding as of December 31,
2003.

     During 2002 warrants issued in conjunction with our acquisition of Bayard
Drilling Technologies, Inc. (April 1999) were exercised, resulting in the
issuance of 18,000 of our common shares.

     As a result of our corporate reorganization on June 24, 2002, the
authorized share capital of Nabors consists of 400 million common shares, par
value $.001 per share, and 25 million preferred shares, par value $.001 per
share. Common shares issued were 146,656,432 and 144,964,668 at $.001 par value
as of December 31, 2003 and 2002, respectively, compared to 144,368,390 at $.10
par value immediately preceding the reorganization. The decrease in par value of
common stock from $.10 to $.001 was recorded as an increase to capital in excess
of par value and a decrease in common shares in our consolidated financial
statements. In conjunction with the reorganization, 6.8 million shares of
outstanding treasury stock
<PAGE>


were retired, as Bermuda law does not recognize the concept of treasury stock.
The effect of this retirement reduced common shares by $.7 million, capital in
excess of par value by $59.2 million and retained earnings by $192.9 million.

     On July 23, 2002, we entered into a private transaction with a counterparty
in which we sold 1.0 million European-style put options for $2.6 million with a
maturity date of October 23, 2002. Under the arrangement, if the price of our
common shares was less than $26.5698 on the maturity date, the counterparty
could have exercised the put option resulting in, at our option (1) our purchase
of 1.0 million of our common shares at a price of $26.5698 per share or (2) our
payment, in cash or Nabors common shares, of an amount equal to the difference
between $26.5698 and our stock price on October 23, 2002 multiplied by 1.0
million. These put options expired on October 23, 2002 and we retained the $2.6
million in proceeds, which was recorded as an increase in capital in excess of
par value in our consolidated balance sheet.

     On July 17, 2002, the Board of Directors of Nabors authorized the
continuation of the share repurchase program that had begun under Nabors
Delaware, and provided that the amount of Nabors common shares authorized for
purchase by Nabors going forward be increased to $400 million. Under the Nabors
Delaware program, Nabors Delaware had acquired an aggregate of approximately
$248.0 million of Nabors Delaware common stock, or 6.2 million shares, during
2001. During 2002 Nabors also acquired, through a subsidiary, 91,000 of its
common shares in the open market for $27.30 per share for an aggregate price of
$2.5 million. Immediately thereafter these shares were transferred to Nabors.
Pursuant to Bermuda law, any shares, when purchased, will be treated as
cancelled. Therefore, a repurchase of shares will not have the effect of
reducing the amount of Nabors' authorized share capital. Additionally, the Board
approved the repurchase of up to $400 million of outstanding debt securities of
Nabors and its subsidiaries. These amounts may be increased or decreased at the
discretion of the Board, depending upon market conditions and consideration of
the best interest of shareholder value. Repurchases may be conducted on the open
market, through negotiated transactions or by other means, from time to time,
depending upon market conditions and other factors.

STOCK OPTION PLANS

     As of December 31, 2003, we have several stock option plans under which
options to purchase Nabors common shares may be granted to key officers,
directors and managerial employees of Nabors and its subsidiaries. Options
granted under the plans are at prices equal to the fair market value of the
shares on the date of the grant. Options granted under the plans generally vest
and are exercisable in varying cumulative periodic installments after one year.
In the case of certain key executives, options granted under the plans are
subject to accelerated vesting related to targeted common share prices, or may
vest immediately on the grant date. Options granted under the plans cannot be
exercised more than ten years from the date of grant. Options to purchase 8.1
million and 5.0 million Nabors common shares remained available for grant as of
December 31, 2003 and 2002, respectively.

     A summary of stock option transactions is as follows:

<Table>
<Caption>
(IN THOUSANDS, EXCEPT EXERCISE PRICE)                           WEIGHTED-
                                                                 AVERAGE
                                                                EXERCISE
                                                 SHARES           PRICE
<S>                                            <C>             <C>
Options outstanding as of December 31,2000         19,071      $    25.65
 Granted                                              881           53.52
 Exercised                                           (556)          14.26
 Forfeited                                           (139)          32.56
                                               ----------      ----------
Options outstanding as of December 31,2001         19,257      $    27.21
 Granted                                            5,495           27.35
 Exercised                                           (806)          12.68
 Forfeited                                           (277)          33.81
                                               ----------      ----------
Options outstanding as of December 31,2002         23,669      $    27.66
 Granted                                            2,969           38.68
 Exercised                                         (1,234)          16.48
 Forfeited                                           (450)          41.45
                                               ----------      ----------
Options outstanding as of December 31,2003         24,954      $    29.27
                                               ----------      ----------
</Table>


     Of the options outstanding, 20.7 million, 20.6 million and 17.2 million
were exercisable at weighted-average exercise prices of $27.65, $27.13 and
$26.46, as of December 31, 2003, 2002 and 2001, respectively.



                                  nbr (92-93)


<PAGE>


     A summary of stock options outstanding as of December 31, 2003 is as
follows:

<Table>
<Caption>
                                                    OPTIONS OUTSTANDING
                                  ----------------------------------------------------------
(IN THOUSANDS, EXCEPT CONTRACTUAL                         WEIGHTED-            WEIGHTED-
LIFE AND EXERCISE PRICE)                                   AVERAGE              AVERAGE
                                       NUMBER             REMAINING            EXERCISE
                                    OUTSTANDING        CONTRACTUAL LIFE          PRICE
<S>                               <C>                  <C>                  <C>
Range of exercise prices:
 $      6.88-10.32                              14                  1.6     $           7.28
       10.38-15.57                           7,133                  3.8                12.47
       15.75-23.63                              28                  5.0                19.19
       24.13-36.19                           8,214                  7.2                26.36
       36.35-54.53                           9,544                  6.2                44.34
       55.30-82.95                              21                  7.1                56.69
                                  ----------------     ----------------     ----------------
                                            24,954                  5.8     $          29.27
                                  ----------------     ----------------     ----------------
</Table>

     A summary of stock options exercisable as of December 31, 2003 is as
follows:

<Table>
<Caption>
                                            OPTIONS EXERCISABLE
                                         -------------------------
(IN THOUSANDS, EXCEPT EXERCISE PRICE)                   WEIGHTED-
                                                         AVERAGE
                                          NUMBER        EXERCISE
                                        EXERCISABLE       PRICE
<S>                                     <C>             <C>
Range of exercise prices:
 $      6.88-10.32                               14     $     7.28
       10.38-15.57                            7,133          12.47
       15.75-23.63                               25          19.10
       24.13-36.19                            7,059          26.10
       36.35-54.53                            6,413          46.28
       55.30-82.95                               10          56.69
                                         ----------     ----------
                                             20,654     $    27.65
                                         ----------     ----------
</Table>


     The weighted-average fair value of options granted during the years ended
December 31, 2003, 2002 and 2001 was $14.29, $10.69 and $22.22, respectively.

11  PENSION, POSTRETIREMENT AND POSTEMPLOYMENT BENEFITS

PENSION PLANS

     In conjunction with our acquisition of Pool Energy Services Co. in November
1999, we acquired the assets and liabilities of a defined benefit pension plan,
the Pool Company Retirement Income Plan. Benefits under the plan are frozen and
participants were fully vested in their accrued retirement benefit on December
31, 1998.

     Summarized information on the Pool pension plan is as follows:

<Table>
<Caption>
PENSION BENEFITS                                   YEAR ENDED DECEMBER 31,
                                                 ---------------------------
(IN THOUSANDS)                                      2003             2002
<S>                                              <C>              <C>
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at beginning of year          $   13,631       $   13,542
Interest cost                                           891              868
Actuarial gain (loss)                                 1,417              (27)
Benefit payments                                       (538)            (752)
                                                 ----------       ----------
Benefit obligation at end of year                    15,401           13,631
                                                 ----------       ----------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning
  of year                                             8,835           10,596
Actual return on plan assets                          1,389           (1,009)
Benefit payments                                       (538)            (752)
                                                 ----------       ----------
Fair value of plan assets at end of
  year                                                9,686            8,835
                                                 ----------       ----------
FUNDED STATUS:
Funded status at end of year                         (5,715)          (4,796)
Unrecognized net actuarial loss                       3,942            3,549
                                                 ----------       ----------
Net liability recognized                         $   (1,773)      $   (1,247)
                                                 ----------       ----------

AMOUNTS RECOGNIZED IN
  CONSOLIDATED BALANCE SHEETS:

  Accrued benefit liability                           5,715            4,381
  Accumulated other comprehensive income              2,815            2,205
                                                 ----------       ----------
COMPONENTS OF NET PERIODIC BENEFIT COST:

Interest cost                                    $      891       $      868
Expected return on plan assets                         (563)            (677)
Recognized net actuarial loss                           198               45
                                                 ----------       ----------
Net periodic benefit cost                        $      526       $      236
                                                 ----------       ----------

Additional information:
Increase in minimum pension liability
included in other comprehensive income           $      610       $    2,205
                                                 ----------       ----------

WEIGHTED-AVERAGE ASSUMPTIONS:
Weighted-average discount rate                         6.00%            6.50%
Expected long-term rate of return
  on plan assets                                       6.50%            6.50%
                                                 ----------       ----------
</Table>


     We analyze the historical performance of investments in equity and debt
securities, together with current market factors such as inflation and interest
rates to help us make the assumptions necessary to estimate a long-term rate of
return on plan assets. Once this estimate is made, we review the portfolio of
plan assets and make adjustments thereto that we believe are necessary to
reflect a diversified blend of investments in equity and debt securities which
is capable of achieving the estimated long-term rate of return without assuming
an unreasonable level of investment risk.

     Our weighted-average asset allocations as of December 31, 2003 and 2002, by
asset category are as follows:

<Table>
<Caption>
PENSION BENEFITS
(IN THOUSANDS)            2003            2002
<S>                   <C>             <C>
Equity securities             56%             54%
Debt securities               43%             44%
Other                          1%              2%
                      ----------      ----------
Total                        100%            100%
                      ----------      ----------
</Table>



<PAGE>


     We invest plan assets based on a total return on investment approach,
pursuant to which our plan assets include a diversified blend of investments in
equity and debt securities towards a goal of maximizing the long-term rate of
return without undertaking an unreasonable level of investment risk. We
determine our acceptable level of risk based on an analysis of plan liabilities,
the extent to which the value of the plan assets satisfies the plan liabilities
and our financial condition. Our investment policy includes target allocations
approximating 55% investment in equity securities and 45% investment in debt
securities. The equity portion of the plan assets represents growth and value
stocks of small, medium and large companies. We measure and monitor the
investment risk of our plan assets on both a quarterly and annual basis when we
assess plan liabilities.

     We expect to contribute approximately $1.5 million to the Pool pension plan
in 2004. This funding is based on the sum of (1) the minimum contribution for
the 2003 plan year that will be made in 2004, and (2) the estimated minimum
required quarterly contributions for the 2004 plan year. There were no
contributions made to the Pool pension plan in 2003.

     Certain of Nabors' employees are covered by defined contribution plans. Our
contributions to the plans are based on employee contributions and totaled
$13.1 million, $9.0 million and $11.0 million for the years ended December 31,
2003, 2002 and 2001, respectively. Nabors does not provide postemployment
benefits to its employees.

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

     Prior to the date of our acquisition, Pool provided certain postretirement
healthcare and life insurance benefits to eligible retirees who had attained
specific age and years of service requirements. Nabors terminated this plan at
the date of acquisition (November 24, 1999). A liability of approximately $.5
million and $.8 million is recorded in our consolidated balance sheets as of
December 31, 2003 and 2002, respectively, to cover the estimated costs of
beneficiaries covered by the plan at the date of acquisition.

12 RELATED PARTY TRANSACTIONS

     Pursuant to his employment agreement entered into in October 1996, we
provided an unsecured, non-interest bearing loan of approximately $2.9 million
to Nabors' Deputy Chairman, President and Chief Operating Officer. This loan is
due on September 30, 2006.

     Pursuant to their employment agreements, Nabors and its Chairman and Chief
Executive Officer, Deputy Chairman, President and Chief Operating Officer, and
certain other key employees entered into split-dollar life insurance agreements
pursuant to which we pay a portion of the premiums under life insurance policies
with respect to these individuals and, in certain instances, members of their
families. Under these agreements, we are reimbursed for such premiums upon the
occurrence of specified events, including the death of an insured individual.
Any recovery of premiums paid by Nabors could potentially be limited to the cash
surrender value of these policies under certain circumstances. As such, the
values of these policies are recorded at their respective cash surrender values
in our consolidated balance sheets. We have made premium payments to date
totaling $12.4 million related to these policies. The cash surrender value of
these policies of approximately $11.4 million and $8.7 million is included in
other long-term assets in our consolidated balance sheets as of December 31,
2003 and 2002, respectively.

     Under the Sarbanes-Oxley Act of 2002, the payment of premiums by Nabors
under the agreements with our Chairman and Chief Executive Officer and with our
Deputy Chairman, President and Chief Operating Officer may be deemed to be
prohibited loans by us to these individuals. We have paid no premiums related to
our agreements with these individuals since the adoption of the Sarbanes-Oxley
Act, and have postponed premium payments related to our agreements with these
individuals.

     In the ordinary course of business, we enter into various rig leases, rig
transportation and related oilfield services agreements with our Alaskan and
Saudi Arabian unconsolidated affiliates at market prices. Additionally, we own
certain marine vessels that are chartered under a bareboat charter arrangement
to Sea Mar Management, which is wholly-owned by Sea Mar Investco LLC, an entity
in which we own a 25% interest. Sea Mar Management has entered into a time
charter of these vessels with a subsidiary of ours, which then time charters the
vessels to various third-party customers. Revenues from these business
transactions totaled $81.6 million, $65.7 million and $26.9 million for the
years ended December 31, 2003, 2002 and 2001, respectively. Expenses from these
business transactions totaled $52.0 million, $32.1 million and $4.8 million for
the years ended December 31, 2003, 2002 and 2001, respectively. Additionally, we
had accounts receivable from these affiliated entities of $24.0 million and
$53.3 million as of December 31, 2003 and 2002,



                                   nbr (94-95)


<PAGE>

respectively. We had accounts payable to these affiliated entities of $3.7
million and $1.1 million as of December 31, 2003 and 2002, respectively.

13 COMMITMENTS AND CONTINGENCIES

OPERATING LEASES

     Nabors and its subsidiaries occupy various facilities and lease certain
equipment under various lease agreements. The minimum rental commitments under
non-cancelable operating leases, with lease terms in excess of one year
subsequent to December 31, 2003, are as follows:

<Table>
<Caption>
(IN THOUSANDS)
<S>                          <C>
2004                         $ 10,096
2005                            7,710
2006                            2,173
2007                            1,470
2008                            1,091
Thereafter                      2,264
                             --------
                             $ 24,804
                             --------
</Table>

     The above amounts do not include property taxes, insurance or normal
maintenance that the lessees are required to pay. Rental expense relating to
operating leases with terms greater than 30 days amounted to $22.4 million,
$21.8 million and $20.3 million for the years ended December 31, 2003, 2002 and
2001, respectively.

     In addition, we have an obligation under our time charter agreement with
Sea Mar Management (Note 12). The minimum commitments under this agreement
subsequent to December 31, 2003 are as follows:

<Table>
<Caption>
(IN THOUSANDS)
<S>                           <C>
2004                          $ 27,056
2005                            26,982
2006                            26,982
2007                            11,606
2008                                --
                              --------
                              $ 92,626
                              --------
</Table>

     Payments under this time charter agreement amounted to $26.9 million and
$16.5 million for the years ended December 31, 2003 and 2002,respectively.

EMPLOYMENT CONTRACTS

     We have entered into employment contracts with certain of our employees.
Our minimum salary and bonus obligations under these contracts as of December
31, 2003 are as follows:

<Table>
<Caption>
(IN THOUSANDS)
<S>                             <C>
2004                            $     1,808
2005                                  1,637
2006                                  1,424
2007                                  1,099
2008                                    123
Thereafter                            1,851
                                -----------
                                $     7,942
                                -----------
</Table>


CAPITAL EXPENDITURES

     As of December 31, 2003, we had outstanding capital expenditure purchase
commitments of approximately $26.1 million, primarily for rig-related enhancing
and sustaining capital expenditures. On October 8, 2003, we entered into two
separate agreements with wholly-owned subsidiaries of El Paso Corporation under
which a subsidiary of Nabors will contribute 20% of an estimated $400 million
total cost to develop approximately 110 wells in exchange for a 20% net profits
interest in such wells (cash proceeds available from production after royalties
and operating costs have been paid). We expect that contributions due from
Nabors to develop these wells will be paid out over a period extending from
October 2003 to December 2004.

     The wells included in these agreements include a combination of proved
undeveloped, probable and possible reserves located primarily in South Texas,
North Louisiana and Offshore Gulf of Mexico. In the event that cash proceeds
totaling 117.5% of our total investment have been received from the wells
subject to the applicable agreement, our net profits interest in those wells
will convert to an overriding royalty interest of 0.4% in the wells for the
remainder of the wells' productive lives. Under the terms of each of the
agreements, either party may terminate the agreement upon 30 days notice. El
Paso will serve as operator of all the wells covered in this development
program.

      On November 6, 2003, we entered into two additional agreements with El
Paso to drill up to a total of 12 exploratory wells in South Texas and South
Louisiana. Through these agreements and a subsequent election under one of the
agreements, we have committed to contribute 25% of El Paso's share of the cost
of drilling and completing eight of the wells; 25% of El Paso's share of the
cost of drilling to casing point for three of the wells; and 20% of El Paso's
share of the cost of drilling to casing point for one of the wells. We are also
committed to contribute 12.5% of El Paso's share of any other costs of the
exploratory wells and of all costs of any development wells in which we elect to
participate on those prospects. In exchange, we receive a 12.5% interest in El
Paso's share in the prospect leases where the exploratory wells are drilled,
subject to certain penalty deductions in the event we elect to participate in
less than all development wells drilled. As of December 31, 2003, three wells
had commenced drilling under these agreements with one being declared a dry
hole, which resulted in a charge to direct costs of $1.4 million recorded during
the fourth quarter of 2003. We expect that contributions due from Nabors for
these agreements will be paid out over a period extending from November 2003 to
June 2005.
<PAGE>


     We estimate that we will contribute approximately $57.1 million and $2.5
million in conjunction with our agreements with El Paso during 2004 and 2005,
respectively. Through December 31, 2003, we have contributed approximately $41.4
million in conjunction with these agreements.

CONTINGENCIES

     PROPOSED COAST GUARD REGULATIONS AND ACTIONS Our Sea Mar division time
charters supply vessels to offshore operators in U.S. waters. On February 4,
2004, the United States Coast Guard took several actions which could adversely
affect our ability to do so.

The vessels are owned by one of our financing company subsidiaries, but are
operated and managed by a U.S. citizen-controlled company pursuant to long-term
bareboat charters (Note 12). Our Sea Mar division time charters the vessels from
this U.S. operating company in connection with our own offshore activities in
the Gulf of Mexico and in support of other offshore operators.

On February 4, 2004, the United States Coast Guard adopted final regulations
which could cause arrangements like that utilized by Sea Mar to no longer
qualify vessels for employment in the U.S. coastwise trades. However, the final
regulations contain grandfathering provisions which could permit us to continue
coastwise marketing of the vessels until the present bareboat charters
terminate. The original term of most of these bareboat charters ends in June
2007, but the charter provides for one or more renewal terms of three to five
years. We believe the grandfathering provisions in these final regulations would
apply to these renewal terms.

Also, on February 4, 2004, the United States Coast Guard proposed a rule which,
if finally adopted, would end the grandfathering provision on February 4, 2007.
In these same proposed regulations, the United States Coast Guard is proposing a
rule under which time charters from a U.S. citizen bareboat charter like the
charter to Sea Mar would no longer be permitted. However, we believe that if
this rule is adopted, the grandfathering provision would apply to the
preexisting SeaMar arrangement.

Additionally, on February 4, 2004, the United States Coast Guard notified us
that it is considering an appeal of the United States Coast Guard's original
issuance in June 2002 of the coastwise trade endorsements for the vessels
bareboat chartered to the U.S. citizen qualified company. The coastwise trade
endorsements on the documents of the vessels issued by the United States Coast
Guard authorize the vessels to engage in the U.S. coastwise trade. If the appeal
is decided against us, we could lose the ability to market the vessels for use
in U.S. waters.

     During 2003 adjusted income derived from operating activities for our Sea
Mar division represented approximately 3.8% of our consolidated adjusted income
derived from operating activities.

     SELF-INSURANCE ACCRUALS We are self-insured for certain losses relating to
workers' compensation, employers' liability, general liability, automobile
liability and property damage. Effective April 1, 2003, with our insurance
renewal, certain changes have been made to our insurance coverage. Effective for
the period from April 1, 2003 to March 31, 2004, our exposure (that is, our
deductible) per occurrence is $1.0 million for workers' compensation, $2.0
million for employers' liability and marine employers' liability (Jones Act)
and $5.0 million for general liability losses. Our self-insurance for automobile
liability loss is $0.5 million per occurrence. We maintain
actuarially-determined accruals in our consolidated balance sheets to cover
the self-insurance retentions.

     We are self-insured for certain other losses relating to rig, equipment,
property, business interruption and political, war and terrorism risks.
Effective April 1, 2003, our per occurrence self-insurance retentions are $10.0
million for rig physical damage and business interruption for 29 specific
high-value rigs. The remainder of the fleet is subject to a $5.0 million
self-insurance retention. However, our rigs, equipment and property in Canada
and Saudi Arabia are subject to $1.0 million self-insurance retentions.

     Political violence (war and terrorism) insurance is procured for our
operations in Mexico, the Caribbean, South America, Africa, the Middle East and
Asia. Political violence losses are subject to $0.25 million per occurrence
deductibles, except for Colombia which is subject to deductibles of $10.0
million and $1.0 million for political violence and terrorism, respectively.
There is no assurance that such coverage will adequately protect Nabors against
liability from all potential consequences.

     As of December 31, 2003 and 2002, our self-insurance accruals totaled
$106.2 million and $117.3 million, respectively, and our related insurance
recoveries/receivables were $31.8 million and $47.6 million, respectively.



                                   nbr (96-97)


<PAGE>


     LITIGATION Nabors and its subsidiaries are defendants or otherwise involved
in a number of lawsuits in the ordinary course of their business. In the opinion
of management, our ultimate liability with respect to these pending lawsuits is
not expected to have a significant or material adverse effect on our
consolidated financial position, results of operations or cash flows.

     GUARANTEES We enter into various agreements providing financial or
performance assurance to third parties. Certain of these agreements serve as
guarantees, including standby letters of credit issued on behalf of insurance
carriers in conjunction with our workers' compensation insurance program and
guarantees of residual value in certain of our operating lease agreements. We
have also guaranteed payment of contingent consideration in conjunction with an
acquisition in 2002, which is based on future operating results of that
business. In addition, we have provided indemnifications to certain third
parties which serve as guarantees. These guarantees include indemnification
provided by Nabors to our stock transfer agent and our insurance carriers. We
are not able to estimate the potential future maximum payments that might be due
under our indemnification guarantees.

     Management believes the likelihood that we would be required to perform or
otherwise incur any significant losses associated with any of these guarantees
is remote. The following table summarizes the total maximum amount of financial
and performance guarantees issued by Nabors:

<Table>
<Caption>
                                                                                MAXIMUM AMOUNT
                                                    ----------------------------------------------------------------------
(IN THOUSANDS)                                         2004           2005           2006        THEREAFTER       TOTAL
<S>                                                 <C>            <C>            <C>            <C>            <C>
Financial standby letters of credit                 $   34,186     $       --     $       --     $       --     $   34,186
Guarantee of residual value in lease agreements            347            684             65             --          1,096
Contingent consideration in acquisition                  1,111          1,111            278             --          2,500
                                                    ----------     ----------     ----------     ----------     ----------
Total                                               $   35,644     $    1,795     $      343     $       --     $   37,782
                                                    ----------     ----------     ----------     ----------     ----------
</Table>


14 EARNINGS PER SHARE

     A reconciliation of the numerators and denominators of the basic and
diluted earnings per share computations is as follows:

<Table>
<Caption>
                                                                                     YEAR ENDED DECEMBER 31,
                                                                                 ----------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)                                           2003         2002         2001
<S>                                                                              <C>          <C>          <C>
Net income (numerator):
  Net income - basic                                                             $192,228     $121,489     $357,450
  Add interest expense on assumed conversion of our
    zero coupon convertible/exchangeable senior debentures/notes, net of tax:
    $825 million due 2020(1)                                                        3,639           --        8,060
    $1.381 billion due 2021(2)                                                         --           --       11,995
    $700 million due 2023(3)                                                           --           --           --
                                                                                 --------     --------     --------
    Adjusted net income - diluted                                                $195,867     $121,489     $377,505
                                                                                 --------     --------     --------
Earnings per share:
  Basic                                                                          $   1.31     $    .85     $   2.48
  Diluted                                                                        $   1.25     $    .81     $   2.24

Shares (denominator):
  Weighted-average number of shares outstanding - basic(4)                        146,495      143,655      144,430
  Net effect of dilutive stock options and warrants based
    on the treasury stock method                                                    6,604        6,342        6,697
  Assumed conversion of our zero coupon convertible/
    exchangeable senior debentures/notes:
    $825 million due 2020(1)                                                        3,798           --        8,852
    $1.381 billion due 2021(2)                                                         --           --        8,811
    $700 million due 2023(3)                                                           --           --           --
                                                                                 --------     --------     --------
WEIGHTED-AVERAGE NUMBER OF SHARES OUTSTANDING - DILUTED                           156,897      149,997      168,790
                                                                                 --------     --------     --------
</Table>


(1)  Diluted earnings per share for the years ended December 31, 2003 and 2001
     reflects the assumed conversion of our $825 million zero coupon convertible
     senior debentures, as the conversion in those years would have been
     dilutive. For the year ended December 31, 2002, the weighted-average number
     of shares outstanding-diluted excludes 8.1 million potentially dilutive
     shares issuable upon the conversion of our $825 million zero coupon
     convertible senior debentures because the inclusion of such shares would
     have been anti-dilutive, given the level of net income for that year. Net
     income for the year ended December 31, 2002 also excludes the related
     add-back of interest expense, net of tax, of $7.6 million for these
     debentures. These shares would have been dilutive and therefore included in
     the calculation of the weighted-average number of shares
     outstanding-diluted had diluted earnings per share been at or above $.93
     for the year ended December 31, 2002.



<PAGE>


((2) Diluted earnings per share for the year ended December 31, 2001 reflects
     the assumed conversion of our $1.381 billion zero coupon convertible senior
     debentures, as the conversion in that year would have been dilutive. For
     the years ended December 31, 2003 and 2002, the weighted-average number of
     shares outstanding-diluted excludes 8.5 million potentially dilutive shares
     issuable upon the conversion of our $1.381 billion zero coupon convertible
     senior debentures because the inclusion of such shares would have been
     anti-dilutive, given the level of net income for those years. Net income
     for the years ended December 31, 2003 and 2002, excludes the related
     add-back of interest expense, net of tax, of $12.1 million and $11.8
     million, respectively, for these debentures. These shares would have been
     dilutive and therefore included in the calculation of the weighted-average
     number of shares outstanding-diluted had diluted earnings per share been at
     or above $1.43 and $1.39 for the years ended December 31, 2003 and 2002,
     respectively.

(3)  Diluted earnings per share for the year ended December 31, 2003 excludes
     approximately 10.0 million potentially dilutive shares initially issuable
     upon the exchange of our $700 million zero coupon exchangeable senior notes
     due 2023. Such shares are contingently exchangeable under certain
     circumstances discussed in Note 8 and would only be included in the
     calculation of the weighted-average number of shares outstanding-diluted if
     any of those criteria were met. Such criteria were not met during the year
     ended December 31, 2003. These notes were issued in June 2003 and therefore
     did not impact the calculation of diluted earnings per share for the years
     ended December 31, 2002 and 2001.

(4)  Includes the following weighted-average number of common shares of Nabors
     and weighted-average number of exchangeable shares of Nabors
     Exchangeco, respectively: 146.0 million and .5 million shares for the year
     ended December 31, 2003; 143.2 million and .4 million shares for the year
     ended December 31, 2002; and 144.4 million and no shares for the year ended
     December 31, 2001. The exchangeable shares of Nabors Exchangeco are
     exchangeable for Nabors common shares on a one-for-one basis, and have
     essentially identical rights as Nabors Industries Ltd. common
     shares, including but not limited to voting rights and the right to receive
     dividends, if any.

     For all periods presented, the computation of diluted earnings per share
excludes outstanding stock options and warrants with exercise prices greater
than the average market price of Nabors' common shares, because the inclusion of
such options and warrants would be anti-dilutive. The number of options and
warrants that were excluded from diluted earnings per share that would
potentially dilute earnings per share in the future were 724,917 shares in 2003,
890,959 shares in 2002 and 919,478 shares in 2001.

     As discussed in Note 8, holders of our $1.381 billion zero coupon
convertible senior debentures and our $700 million zero coupon senior
exchangeable notes have the right to require us to repurchase the
debentures/notes at various dates commencing February 5, 2006 and June 15, 2008,
respectively. We may pay the redemption prices with either cash or shares or a
combination thereof. We do not presently anticipate using shares to satisfy any
such future purchase obligations.

15  SUPPLEMENTAL BALANCE SHEET, INCOME STATEMENT AND CASH FLOW INFORMATION

     Accounts receivable is net of an allowance for doubtful accounts of $11.0
million and $13.8 million as of December 31, 2003 and 2002, respectively. Other
current assets include an investment in overseas funds of $47.0 million and
$15.0 million as of December 31, 2003 and 2002, respectively.

     Accrued liabilities include the following:

<Table>
<Caption>
                                          DECEMBER 31,
                                      ---------------------
(IN THOUSANDS)                          2003         2002
<S>                                   <C>          <C>
Accrued compensation                  $ 55,137     $ 40,761
Deferred revenue                        26,611       33,157
Workers' compensation liabilities       30,180       16,926
Interest payable                        15,888       16,431
Other accrued liabilities               32,929       26,131
                                      --------     --------
                                      $160,745     $133,406
                                      --------     --------
</Table>


     Other income includes the following:

<Table>
<Caption>
                                        YEAR ENDED DECEMBER 31,
                                  ------------------------------------
(IN THOUSANDS)                      2003          2002          2001
<S>                               <C>           <C>           <C>
Gains on marketable
  and non-marketable
  securities, net                 $  6,145      $  2,877      $    989
Gains on long-term assets, net       2,476         4,570        10,246
Foreign currency
  transaction gains                    830           486           419
Corporate reorganization
  expense                               --        (3,769)           --
Losses on derivative
  instruments                       (1,140)       (1,983)           --
(Loss) gain on extinguishment
  of debt                             (908)         (202)       15,330
Other                               (2,495)        1,729         1,666
                                  --------      --------      --------
                                  $  4,908      $  3,708      $ 28,650
                                  --------      --------      --------
</Table>


     Supplemental cash flow information for the years ended December 31, 2003,
2002 and 2001 is as follows:

<Table>
<Caption>
                                            YEAR ENDED DECEMBER 31,
                                    --------------------------------------
(IN THOUSANDS)                         2003          2002           2001
<S>                                 <C>           <C>            <C>
Cash paid for income taxes          $  16,542     $  22,831      $  82,831
Cash paid for interest,
  net of capitalized interest          41,033        22,653         24,614
Acquisitions of businesses:
  Fair value of assets acquired            --       305,399        111,034
  Goodwill                                 --       110,636         12,909
  Liabilities assumed
   or created                              --      (105,986)       (54,372)
  Common stock of acquired
   company previously owned                --          (282)            --
  Equity consideration issued              --      (174,115)            --
                                    ---------     ---------      ---------
Cash paid for acquisitions
  of businesses                            --       135,652         69,571
Cash acquired in acquisitions
  of businesses                            --            --         (3,219)
                                    ---------     ---------      ---------
Cash paid for acquisitions
  of businesses, net                $      --     $ 135,652      $  66,352
                                    ---------     ---------      ---------
</Table>



                                   nbr (98-99)


<PAGE>
16  UNAUDITED QUARTERLY FINANCIAL INFORMATION

<Table>
<Caption>
                                                                       YEAR ENDED DECEMBER 31, 2003
                                                        -----------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)                                       Quarter Ended
                                                         March 31,        June 30,     September 30,   December 31,
<S>                                                     <C>             <C>            <C>             <C>
Operating revenues and Earnings from unconsolidated
  affiliates(1)                                         $   455,740     $   433,911     $   475,979     $   524,556
Net income                                                   48,057          29,019          50,281          64,871
Earnings per share:(2)
  Basic                                                 $       .33     $       .20     $       .34     $       .44
  Diluted                                               $       .31     $       .19     $       .33     $       .42
                                                        -----------     -----------     -----------     -----------
</Table>


<Table>
<Caption>
                                                                       YEAR ENDED DECEMBER 31, 2002
                                                        -----------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)                                        Quarter Ended
                                                         March 31,        June 30,     September 30,   December 31,
<S>                                                     <C>             <C>            <C>             <C>
Operating revenues and Earnings from unconsolidated
  affiliates(3)                                         $   386,837     $   356,518     $   355,078     $   382,785
Net income                                                   41,942          25,420          26,922          27,205
Earnings per share:(2)
  Basic                                                 $       .30     $       .18     $       .19     $       .19
  Diluted                                               $       .28     $       .17     $       .18     $       .18
                                                        -----------     -----------     -----------     -----------
</Table>


(1)  Includes Earnings from unconsolidated affiliates, accounted for by the
     equity method, of $5.9 million,$1.4 million,$2.5 million and $.4
     million, respectively.

(2)  Earnings per share is computed independently for each of the quarters
     presented. Therefore, the sum of the quarterly earnings per share may not
     equal the total computed for the year.

(3)  Includes Earnings from unconsolidated affiliates, accounted for by the
     equity method, of $5.6 million,$4.4 million,$1.9 million and $2.8
     million, respectively.

17  SEGMENT INFORMATION

     As of December 31, 2003, we operate our business out of 13 operating
segments. Our six Contract Drilling operating segments are engaged in drilling,
workover and well-servicing operations, on land and offshore, and represent
reportable segments. These operating segments consist of our Alaska, U.S. Lower
48 Land Drilling, U.S. Land Well-servicing, U.S. Offshore, Canada and
International business units. Our oil and gas operating segment, Ramshorn
Investments, Inc., is engaged in the exploration for, development of and
production of oil and gas and is included in our Oil and Gas reportable segment.
Our Other Operating Segments, consisting of Canrig Drilling Technology Ltd.,
Epoch Well Services, Inc., Peak Oilfield Service Company, Peak USA Energy
Services, Ltd., Ryan Energy Technologies and Sea Mar, a division of Pool Well
Services Co., are engaged in the manufacturing of top drives, manufacturing of
drilling instrumentation systems, construction and logistics services, trucking
and logistics services, manufacturing and marketing of directional drilling and
rig instrumentation systems, directional drilling, rig instrumentation and data
collection services, and marine transportation and supply services,
respectively. These Other Operating Segments do not meet the criteria included
in SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information" for disclosure, individually or in the aggregate, as reportable
segments. Our segment information as of and for the years ended December 31,
2002 and 2001 has been revised to conform to the current period presentation.

     The accounting policies of the segments are the same as those described in
the Summary of Significant Accounting Policies (Note 2). Inter-segment sales are
recorded at cost or cost plus a profit margin. We evaluate the performance of
our segments based on adjusted income derived from operating activities.



<PAGE>


     The following tables set forth certain financial information with respect
to our reportable segments:

<Table>
<Caption>
                                                                                 YEAR ENDED DECEMBER 31,
                                                                      ---------------------------------------------
(IN THOUSANDS)                                                            2003             2002             2001
<S>                                                                   <C>              <C>              <C>
  Operating revenues and Earnings from unconsolidated affiliates:
  Contract Drilling:
    U.S. Lower 48 Land Drilling                                       $   476,258      $   374,659      $ 1,007,300
    U.S. Land Well-servicing                                              312,279          294,428          345,785
    U.S. Offshore                                                         101,566          105,717          226,078
    Alaska                                                                112,092          118,199          133,634
    Canada                                                                322,303          141,497           86,310
    International                                                         396,884          320,160          282,404
                                                                      -----------      -----------      -----------
      Subtotal Contract Drilling(1)                                     1,721,382        1,354,660        2,081,511
  Oil and Gas                                                              16,919            7,223            5,529
  Other Operating Segments(2)                                             201,660          174,775          259,298
  Other reconciling items(3)                                              (49,775)         (55,440)        (118,268)
                                                                      -----------      -----------      -----------
    Total                                                             $ 1,890,186      $ 1,481,218      $ 2,228,070
                                                                      -----------      -----------      -----------
Depreciation and amortization, and depletion:
  Contract Drilling:
    U.S. Lower 48 Land Drilling                                       $    69,190      $    61,022      $    72,954
    U.S. Land Well-servicing                                               22,163           19,600           17,957
    U.S. Offshore                                                          19,794           20,491           25,231
    Alaska                                                                 11,969           12,000           14,459
    Canada                                                                 29,840           20,713            6,502
    International                                                          53,374           37,521           31,045
                                                                      -----------      -----------      -----------
      Subtotal Contract Drilling                                          206,330          171,347          168,148
  Oil and Gas                                                               8,599            7,700            5,777
  Other Operating Segments                                                 21,597           18,044           17,923
  Other reconciling items(3)                                               (1,399)          (1,726)          (1,952)
                                                                      -----------      -----------      -----------
    Total depreciation and amortization, and depletion                $   235,127      $   195,365      $   189,896
                                                                      -----------      -----------      -----------
Adjusted income (loss) derived from operating activities:(4)
  Contract Drilling:
    U.S. Lower 48 Land Drilling                                       $    16,800      $    23,415      $   286,856
    U.S. Land Well-servicing                                               47,082           38,631           64,446
    U.S. Offshore                                                           1,649           (1,397)          29,874
    Alaska                                                                 37,847           31,387           30,445
    Canada                                                                 59,856           17,413           30,971
    International                                                          77,964           76,121           58,549
                                                                      -----------      -----------      -----------
      Subtotal Contract Drilling                                          241,198          185,570          501,141
  Oil and Gas                                                               5,850           (1,058)            (737)
  Other Operating Segments(2)                                               3,266           24,660           87,847
  Other reconciling items(5)                                              (37,611)         (39,124)         (52,540)
                                                                      -----------      -----------      -----------
    Total adjusted income derived from operating activities           $   212,703      $   170,048      $   535,711
Interest expense                                                          (70,740)         (67,068)         (60,722)
Interest income                                                            27,752           34,086           53,973
Other income, net                                                           4,908            3,708           28,650
                                                                      -----------      -----------      -----------
  Income before income taxes                                          $   174,623      $   140,774      $   557,612
                                                                      -----------      -----------      -----------
</Table>



                                  nbr (100-101)


<PAGE>


<Table>
<Caption>
                                                                   YEAR ENDED DECEMBER 31,
                                                        --------------------------------------------
(IN THOUSANDS)                                             2003             2002             2001
<S>                                                     <C>             <C>              <C>
Capital expenditures and acquisition of businesses:
  Contract Drilling:
    U.S. Lower 48 Land Drilling                         $    72,528     $     7,488      $   330,684
    U.S. Land Well-servicing                                 25,052          35,901           43,591
    U.S. Offshore                                            36,785          32,585           77,850
    Alaska                                                    3,940          21,018           21,458
    Canada                                                   31,068         370,500          111,811
    International                                           128,247         194,739          180,225
                                                        -----------     -----------      -----------
      Subtotal Contract Drilling                            297,620         662,231          765,619
  Oil and Gas                                                53,716           9,733           11,449
  Other Operating Segments                                    5,827          32,076           33,002
  Other reconciling items(5)                                    230          (1,197)          (6,829)
                                                        -----------     -----------      -----------
    Total capital expenditures                          $   357,393     $   702,843      $   803,241
                                                        -----------     -----------      -----------
Total assets:
  Contract Drilling:(6)
    U.S. Lower 48 Land Drilling                         $   987,903     $   972,495      $ 1,106,953
    U.S. Land Well-servicing                                246,312         237,594          231,955
    U.S. Offshore                                           386,196         368,267          398,516
    Alaska                                                  218,222         215,706          229,360
    Canada                                                  767,400         565,458          185,995
    International                                         1,001,058         883,255          699,590
                                                        -----------     -----------      -----------
      Subtotal Contract Drilling                          3,607,091       3,242,775        2,852,369
  Oil and Gas                                                67,898          23,517           20,165
  Other Operating Segments(7)                               337,622         343,365          311,629
  Other reconciling items(5)                              1,590,081       1,454,215          967,752
                                                        -----------     -----------      -----------
    Total assets                                        $ 5,602,692     $ 5,063,872      $ 4,151,915
                                                        -----------     -----------      -----------
</Table>


(1)  Includes Earnings from unconsolidated affiliates, accounted for by the
     equity method, of $2.8 million, $3.9 million and $9.0 million for the years
     ended December 31, 2003, 2002 and 2001, respectively.

(2)  Includes Earnings from unconsolidated affiliates, accounted for by the
     equity method, of $7.4 million, $10.9 million and $17.3 million for the
     years ended December 31, 2003, 2002 and 2001, respectively.

(3)  Represents the elimination of inter-segment transactions.

(4)  Adjusted income (loss) derived from operating activities is computed by:
     subtracting direct costs, general and administrative expenses, and
     depreciation and amortization, and depletion expense from Operating
     revenues and then adding Earnings from unconsolidated affiliates. Such
     amounts should not be used as a substitute to those amounts reported under
     GAAP. However, management evaluates the performance of our business units
     and the consolidated company based on several criteria, including adjusted
     income (loss) derived from operating activities, because it believes that
     this financial measure is an accurate reflection of the ongoing
     profitability of our company. A reconciliation of this non-GAAP measure to
     income before income taxes, which is a GAAP measure, is provided within the
     table above.

(5)  Represents the elimination of inter-segment transactions and unallocated
     corporate expenses, assets and capital expenditures.

(6)  Includes $26.5 million, $25.3 million and $22.3 million of investments in
     unconsolidated affiliates accounted for by the equity method as of December
     31, 2003, 2002 and 2001, respectively.

(7)  Includes $31.6 million, $33.3 million and $32.8 million of investments in
     unconsolidated affiliates accounted for by the equity method as of December
     31, 2003, 2002 and 2001, respectively.

     The following table sets forth certain financial information with respect
to Nabors operations by geographic area:

<Table>
<Caption>
                                                                            YEAR ENDED DECEMBER 31,
                                                                    ----------------------------------------
(IN THOUSANDS)                                                         2003           2002           2001
<S>                                                                 <C>            <C>            <C>
Operating revenues and Earnings from unconsolidated affiliates:
  United States                                                     $1,152,272     $1,012,503     $1,859,356
  Foreign                                                              737,914        468,715        368,714
                                                                    ----------     ----------     ----------
                                                                    $1,890,186     $1,481,218     $2,228,070
                                                                    ----------     ----------     ----------
Property, plant and equipment, net:
  United States                                                     $1,823,281     $1,759,199     $1,834,548
  Foreign                                                            1,167,511      1,041,868        616,838
                                                                    ----------     ----------     ----------
                                                                    $2,990,792     $2,801,067     $2,451,386
                                                                    ----------     ----------     ----------
Goodwill, net:
  United States                                                     $  157,873     $  165,609     $  165,694
  Foreign                                                              178,154        141,153         33,354
                                                                    ----------     ----------     ----------
                                                                    $  336,027     $  306,762     $  199,048
                                                                    ----------     ----------     ----------
</Table>



<PAGE>


18 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

     Nabors has fully and unconditionally guaranteed all of the issued public
debt securities of Nabors Delaware, and Nabors and Nabors Delaware have fully
and unconditionally guaranteed the $225 million 4.875% senior notes due 2009
issued by Nabors Holdings 1, ULC, our indirect subsidiary.

     The following condensed consolidating financial information is included so
that separate financial statements of Nabors Delaware and Nabors Holdings are
not required to be filed with the U.S. Securities and Exchange Commission. The
condensed consolidating financial statements present investments in both
consolidated and unconsolidated affiliates using the equity method of
accounting.

     The following condensed consolidating financial information presents:
condensed consolidating balance sheets as of December 31, 2003 and 2002,
statements of income and cash flows for each of the three years in the period
ended December 31, 2003 of (a) Nabors, parent/guarantor, (b) Nabors Delaware,
issuer of public debt securities guaranteed by Nabors and guarantor of the $225
million 4.875% senior notes issued by Nabors Holdings, (c) Nabors Holdings,
issuer of the $225 million 4.875% senior notes, (d) the non-guarantor
subsidiaries, (e) consolidating adjustments necessary to consolidate Nabors and
its subsidiaries and (f) Nabors on a consolidated basis.

CONDENSED CONSOLIDATING BALANCE SHEETS

<Table>
<Caption>
                                                                       DECEMBER 31, 2003
                                       ------------------------------------------------------------------------------------
(IN THOUSANDS)                                         NABORS                        OTHER
                                          NABORS      DELAWARE        NABORS      SUBSIDIARIES
                                         (PARENT/     (ISSUER/       HOLDINGS        (NON-      CONSOLIDATING  CONSOLIDATED
                                        GUARANTOR)   GUARANTOR)      (ISSUER)      GUARANTORS)   ADJUSTMENTS      TOTAL
                                       -----------   -----------    -----------    -----------   -----------    -----------
<S>                                    <C>           <C>            <C>           <C>           <C>            <C>
ASSETS
Current assets:
  Cash and cash equivalents            $   403,693   $         1    $        17    $   176,026   $        --    $   579,737
  Marketable securities                    285,353            --             --         54,583            --        339,936
  Accounts receivable, net                      --            --             --        410,487            --        410,487
  Inventory and supplies                        --            --             --         23,289            --         23,289
  Other current assets                       6,806         4,229             --        151,163            --        162,198
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL CURRENT ASSETS                   695,852         4,230             17        815,548            --      1,515,647
  Marketable securities                    571,327            --             --         41,090            --        612,417
  Property, plant and equipment,net             --            --             --      2,990,792            --      2,990,792
  Goodwill, net                                 --            --             --        336,027            --        336,027
  Intercompany receivables               1,057,260     1,085,944            202             --    (2,143,406)            --
  Investments in affiliates                170,089     2,065,230        236,829      1,095,882    (3,509,930)        58,100
  Other long-term assets                        --        20,359            966         68,384            --         89,709
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL ASSETS                       $ 2,494,528   $ 3,175,763    $   238,014    $ 5,347,723   $(5,653,336)   $ 5,602,692
                                       -----------   -----------    -----------    -----------   -----------    -----------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
  Current portion of long-term debt    $        --   $   295,267    $        --    $     4,118   $        --    $   299,385
  Trade accounts payable                         1            23             --        128,816            --        128,840
  Accrued liabilities                          960        10,766          3,901        145,118            --        160,745
  Income taxes payable                       1,164          (190)          (111)         8,540            --          9,403
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL CURRENT LIABILITIES                2,125       305,866          3,790        286,592            --        598,373
Long-term debt                                  --     1,762,054        223,499             --            --      1,985,553
Other long-term liabilities                     --         3,738             --        151,929            --        155,667
Deferred income taxes                           79        61,623             82        311,040            --        372,824
Intercompany payable                         2,049            --             --      2,141,357    (2,143,406)            --
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL LIABILITIES                        4,253     2,133,281        227,371      2,890,918    (2,143,406)     3,112,417
                                       -----------   -----------    -----------    -----------   -----------    -----------
SHAREHOLDERS' EQUITY                     2,490,275     1,042,482         10,643      2,456,805    (3,509,930)     2,490,275
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL LIABILITIES AND
      SHAREHOLDERS' EQUITY             $ 2,494,528   $ 3,175,763    $   238,014    $ 5,347,723   $(5,653,336)   $ 5,602,692
                                       -----------   -----------    -----------    -----------   -----------    -----------
</Table>



                                  nbr (102-103)


<PAGE>



<Table>
<Caption>
                                                                       DECEMBER 31, 2002
                                       ------------------------------------------------------------------------------------
(IN THOUSANDS)                                         NABORS                        OTHER
                                          NABORS      DELAWARE        NABORS      SUBSIDIARIES
                                         (PARENT/     (ISSUER/       HOLDINGS        (NON-      CONSOLIDATING  CONSOLIDATED
                                        GUARANTOR)   GUARANTOR)      (ISSUER)      GUARANTORS)   ADJUSTMENTS      TOTAL
                                       -----------   -----------    -----------    -----------   -----------    -----------
<S>                                    <C>           <C>            <C>           <C>           <C>            <C>
ASSETS
Current assets:
  Cash and cash equivalents            $    40,127   $        38    $       207    $   373,679   $        --    $   414,051
  Marketable securities                      5,721            --             21        451,858            --        457,600
  Accounts receivable, net                      --            --             --        320,299            --        320,299
  Inventory and supplies                        --            --             --         20,524            --         20,524
  Other current assets                          --         2,607             --        154,827            --        157,434
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL CURRENT ASSETS                    45,848         2,645            228      1,321,187            --      1,369,908
Marketable securities                       19,378            --             --        439,770            --        459,148
Property, plant and equipment,net               --            --             --      2,801,067            --      2,801,067
Goodwill, net                                   --            --             --        306,762            --        306,762
Intercompany receivables                 2,009,672     2,158,524            140             --    (4,168,336)            --
Investments in affiliates                   84,887     1,773,633        221,484      2,092,224    (4,113,589)        58,639
Other long-term assets                          --        20,150          1,220         46,978            --         68,348
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL ASSETS                       $ 2,159,785   $ 3,954,952    $   223,072    $ 7,007,988   $(8,281,925)   $ 5,063,872
                                       -----------   -----------    -----------    -----------   -----------    -----------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
  Current portion of long-term debt    $        --   $   489,126    $        --    $     3,859   $        --    $   492,985
  Trade accounts payable                         4            23             --        109,136            --        109,163
  Accrued liabilities                          217        10,168          3,930        119,091            --        133,406
  Income taxes payable                         892          (189)            --         15,197            --         15,900
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL CURRENT LIABILITIES                1,113       499,128          3,930        247,283            --        751,454
Long-term debt                                  --     1,343,686        223,234         47,736            --      1,614,656
Other long-term liabilities                     --         3,763             --        157,990            --        161,753
Deferred income taxes                          152        72,258         (1,560)       306,704            --        377,554
Intercompany payable                            65            --             --      4,168,271    (4,168,336)            --
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL LIABILITIES                        1,330     1,918,835        225,604      4,927,984    (4,168,336)     2,905,417
                                       -----------   -----------    -----------    -----------   -----------    -----------
SHAREHOLDERS' EQUITY                     2,158,455     2,036,117         (2,532)     2,080,004    (4,113,589)     2,158,455
                                       -----------   -----------    -----------    -----------   -----------    -----------
    TOTAL LIABILITIES AND
      SHAREHOLDERS' EQUITY             $ 2,159,785   $ 3,954,952    $   223,072    $ 7,007,988   $(8,281,925)   $ 5,063,872
                                       -----------   -----------    -----------    -----------   -----------    -----------
</Table>



<PAGE>


CONDENSED CONSOLIDATING STATEMENTS OF INCOME


<Table>
<Caption>
                                                                       YEAR ENDED DECEMBER 31, 2003
                                            ------------------------------------------------------------------------------------
(IN THOUSANDS)                                              NABORS                        OTHER
                                              NABORS       DELAWARE        NABORS      SUBSIDIARIES
                                             (PARENT/       (ISSUER/      HOLDINGS        (NON-      CONSOLIDATING  CONSOLIDATED
                                            GUARANTOR)     GUARANTOR)     (ISSUER)      GUARANTORS)   ADJUSTMENTS      TOTAL
                                            -----------   -----------    -----------   ------------  -------------  ------------
<S>                                         <C>           <C>            <C>           <C>           <C>            <C>
REVENUES AND OTHER INCOME:
  Operating revenues                        $        --    $        --    $        --   $ 1,880,003    $        --    $ 1,880,003
  Earnings from unconsolidated affiliates            --             --             --        10,183             --         10,183
  Earnings from consolidated affiliates           6,314        133,011         15,345       119,736       (274,406)            --
  Interest income                                 1,775             34             11        25,932             --         27,752
  Intercompany interest income                  207,615         59,276             --            --       (266,891)            --
  Other income (expense), net                    (3,890)        (1,140)            15         9,923             --          4,908
                                            -----------    -----------    -----------   -----------    -----------    -----------
    Total revenues and other income             211,814        191,181         15,371     2,045,777       (541,297)     1,922,846
                                            -----------    -----------    -----------   -----------    -----------    -----------
Costs and other deductions:
  Direct costs                                       --             --             --     1,276,953             --      1,276,953
  General and administrative expenses             3,298            (48)             8       162,145             --        165,403
  Depreciation and amortization                      --             --             --       226,528             --        226,528
  Depletion                                          --             --             --         8,599             --          8,599
  Interest expense                                   --         58,785         11,448           507             --         70,740
  Intercompany interest expense                      --             --             --       266,891       (266,891)            --
                                            -----------    -----------    -----------   -----------    -----------    -----------
    Total costs and other deductions              3,298         58,737         11,456     1,941,623       (266,891)     1,748,223
                                            -----------    -----------    -----------   -----------    -----------    -----------
Income before income taxes                      208,516        132,444          3,915       104,154       (274,406)       174,623
                                            -----------    -----------    -----------   -----------    -----------    -----------
Income tax expense (benefit)                     16,288           (210)         1,488       (35,171)            --        (17,605)
                                            -----------    -----------    -----------   -----------    -----------    -----------
Net income                                  $   192,228    $   132,654    $     2,427   $   139,325    $  (274,406)   $   192,228
                                            -----------    -----------    -----------   -----------    -----------    -----------
</Table>


<Table>
<Caption>
                                                                       YEAR ENDED DECEMBER 31, 2002
                                            ----------------------------------------------------------------------------------------
(IN THOUSANDS)                                              NABORS                        OTHER
                                               NABORS      DELAWARE        NABORS      SUBSIDIARIES
                                              (PARENT/     (ISSUER/       HOLDINGS        (NON-       CONSOLIDATING    CONSOLIDATED
                                             GUARANTOR)   GUARANTOR)      (ISSUER)      GUARANTORS)    ADJUSTMENTS        TOTAL
                                            -----------   -----------    -----------   ------------   -------------    -------------
<S>                                         <C>           <C>            <C>           <C>            <C>              <C>
REVENUES AND OTHER INCOME:
  Operating revenues                        $        --   $        --    $        --    $ 1,466,443   $          --    $   1,466,443
  Earnings from unconsolidated affiliates            --            --             --         14,775              --           14,775
  Earnings from consolidated affiliates          18,159        89,947             --         79,525        (187,631)              --
  Interest income                                    48            49             --         33,989              --           34,086
  Intercompany interest income                  101,436        54,326             --             --        (155,762)              --
  Other income (expense), net                     3,469        (6,191)            --          6,430              --            3,708
                                            -----------   -----------    -----------    -----------   -------------    -------------
    Total revenues and other income             123,112       138,131             --      1,601,162        (343,393)       1,519,012
                                            -----------   -----------    -----------    -----------   -------------    -------------
Costs and other deductions:
  Direct costs                                       --            --             --        973,910              --          973,910
  General and administrative expenses               579           483              2        140,831              --          141,895
  Depreciation and amortization                      --            --             --        187,665              --          187,665
  Depletion                                          --            --             --          7,700              --            7,700
  Interest expense                                   --        60,206          4,102          2,760              --           67,068
  Intercompany interest expense                      --            --             --        155,762        (155,762)              --
                                            -----------   -----------    -----------    -----------   -------------    -------------
    Total costs and other deductions                579        60,689          4,104      1,468,628        (155,762)       1,378,238
                                            -----------   -----------    -----------    -----------   -------------    -------------
Income (loss) before income taxes               122,533        77,442         (4,104)       132,534        (187,631)         140,774
                                            -----------   -----------    -----------    -----------   -------------    -------------
Income tax expense (benefit)                      1,044        (4,627)        (1,560)        24,428              --           19,285
                                            -----------   -----------    -----------    -----------   -------------    -------------
NET INCOME (LOSS)                           $   121,489   $    82,069    $    (2,544)   $   108,106   $    (187,631)   $     121,489
                                            -----------   -----------    -----------    -----------   -------------    -------------
</Table>



                                  nbr (104-105)


<PAGE>


<Table>
<Caption>
                                                                     YEAR ENDED DECEMBER 31, 2001
                                            ----------------------------------------------------------------------------------
(IN THOUSANDS)                                              NABORS                      OTHER
                                               NABORS      DELAWARE       NABORS     SUBSIDIARIES
                                              (PARENT/     (ISSUER/      HOLDINGS       (NON-      CONSOLIDATING  CONSOLIDATED
                                             GUARANTOR)   GUARANTOR)     (ISSUER)     GUARANTORS)   ADJUSTMENTS      TOTAL
                                            -----------   -----------   -----------   -----------   -----------    -----------
<S>                                         <C>           <C>           <C>          <C>           <C>            <C>
REVENUES AND OTHER INCOME:
  Operating revenues                        $        --   $        --   $        --   $ 2,201,736   $        --    $ 2,201,736
  Earnings from unconsolidated affiliates            --            --            --        26,334            --         26,334
  Earnings from consolidated affiliates              --       336,851            --            --      (336,851)            --
  Interest income                                    --            53            --        53,920            --         53,973
  Intercompany interest income                       --        77,211            --            --       (77,211)            --
  Other income, net                                  --        14,301            --        14,349            --         28,650
                                            -----------   -----------   -----------   -----------   -----------    -----------
    Total revenues and other income                  --       428,416            --     2,296,339      (414,062)     2,310,693
                                            -----------   -----------   -----------   -----------   -----------    -----------
Costs and other deductions:
  Direct costs                                       --            --            --     1,366,967            --      1,366,967
  General and administrative expenses                --           482            --       135,014            --        135,496
  Depreciation and amortization                      --            --            --       184,119            --        184,119
  Depletion                                          --            --            --         5,777            --          5,777
  Interest expense                                   --        58,386            --         2,336            --         60,722
  Intercompany interest expense                      --            --            --        77,211       (77,211)            --
                                            -----------   -----------   -----------   -----------   -----------    -----------
    Total costs and other deductions                 --        58,868            --     1,771,424       (77,211)     1,753,081
                                            -----------   -----------   -----------   -----------   -----------    -----------
Income before income taxes                           --       369,548            --       524,915      (336,851)       557,612
                                            -----------   -----------   -----------   -----------   -----------    -----------
Income tax expense                                   --        12,098            --       188,064            --        200,162
                                            -----------   -----------   -----------   -----------   -----------    -----------
NET INCOME                                  $        --   $   357,450   $        --   $   336,851   $  (336,851)   $   357,450
                                            -----------   -----------   -----------   -----------   -----------    -----------
</Table>



CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


<Table>
<Caption>
                                                                        YEAR ENDED DECEMBER 31, 2003
                                            ------------------------------------------------------------------------------------
(IN THOUSANDS)                                               NABORS                        OTHER
                                               NABORS       DELAWARE        NABORS      SUBSIDIARIES
                                              (PARENT/      (ISSUER/       HOLDINGS         (NON-      CONSOLIDATING  CONSOLIDATED
                                             GUARANTOR)    GUARANTOR)      (ISSUER)      GUARANTORS)    ADJUSTMENTS       TOTAL
                                            -----------    -----------    -----------    -----------    -----------    -----------
<S>                                         <C>            <C>            <C>           <C>            <C>            <C>
NET CASH PROVIDED BY (USED FOR)
  OPERATING ACTIVITIES                      $   169,665    $   641,821    $   (10,786)   $   408,517    $  (813,386)   $   395,831
                                            -----------    -----------    -----------    -----------    -----------    -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Purchases of marketable
    securities, available-for-sale             (908,529)            --             --     (1,202,798)       681,782     (1,429,545)
  Sales of marketable securities,
    available-for-sale                           77,640             --             --      1,997,780       (681,782)     1,393,638
  Purchases of non-marketable
    securities, net                                  --             --             --        (29,496)            --        (29,496)
  Cash paid for investments in
    consolidated affiliates                          --       (700,484)            --           (236)       700,720             --
  Capital expenditures                               --             --             --       (353,406)            --       (353,406)
  Proceeds from sales of assets
    and insurance claims                             --             --             --         10,476             --         10,476
                                            -----------    -----------    -----------    -----------    -----------    -----------
NET CASH (USED FOR) PROVIDED BY
  INVESTING ACTIVITIES                         (830,889)      (700,484)            --        422,320        700,720       (408,333)
                                            -----------    -----------    -----------    -----------    -----------    -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Decrease in cash overdrafts                        --             --             --           (778)            --           (778)
  Decrease in restricted cash                        --             --             --          1,925             --          1,925
  Proceeds from long-term debt                       --        700,000             --             --             --        700,000
  Retirement of intercompany loan               998,675             --             --       (998,675)            --             --
  Reduction in long-term debt                        --       (494,903)            --        (49,576)            --       (544,479)
  Debt issuance costs                                --        (11,366)          (159)            --             --        (11,525)
  Proceeds from issuance of common shares        26,115             --             --            226             --         26,341
  Proceeds from parent contributions                 --             --         10,755        689,965       (700,720)            --
  Cash dividends paid                                --       (135,105)            --       (678,281)       813,386             --
                                            -----------    -----------    -----------    -----------    -----------    -----------
NET CASH PROVIDED BY (USED FOR)
  FINANCING ACTIVITIES                        1,024,790         58,626         10,596     (1,035,194)       112,666        171,484
                                            -----------    -----------    -----------    -----------    -----------    -----------
EFFECT OF EXCHANGE RATE CHANGES ON
  CASH AND CASH EQUIVALENTS                          --             --             --          6,704             --          6,704
                                            -----------    -----------    -----------    -----------    -----------    -----------
NET INCREASE (DECREASE) IN CASH AND
  CASH EQUIVALENTS                              363,566            (37)          (190)      (197,653)            --        165,686
CASH AND CASH EQUIVALENTS,
  BEGINNING OF PERIOD                            40,127             38            207        373,679             --        414,051
                                            -----------    -----------    -----------    -----------    -----------    -----------
CASH AND CASH EQUIVALENTS, END
  OF PERIOD                                 $   403,693    $         1    $        17    $   176,026    $        --    $   579,737
                                            -----------    -----------    -----------    -----------    -----------    -----------
</Table>



<PAGE>


<Table>
<Caption>
                                                                         YEAR ENDED DECEMBER 31, 2002
                                             --------------------------------------------------------------------------------------
(IN THOUSANDS)                                                NABORS                        OTHER
                                               NABORS        DELAWARE        NABORS      SUBSIDIARIES
                                              (PARENT/       (ISSUER/       HOLDINGS         (NON-      CONSOLIDATING  CONSOLIDATED
                                             GUARANTOR)     GUARANTOR)      (ISSUER)      GUARANTORS)    ADJUSTMENTS       TOTAL
                                             -----------    -----------    -----------    -----------    -----------    -----------
<S>                                          <C>            <C>            <C>           <C>            <C>            <C>
NET CASH PROVIDED BY (USED FOR)
  OPERATING ACTIVITIES                       $    78,235    $  (193,818)   $      (128)   $   597,850    $   (81,263)   $   400,876
                                             -----------    -----------    -----------    -----------    -----------    -----------
CASH FLOWS FROM INVESTING
  ACTIVITIES:
  Purchases of marketable
    securities, available-for-sale               (25,055)            --            (21)      (720,307)            --       (745,383)
  Sales of marketable securities,
    available-for-sale                                --             --             --        542,133             --        542,133
  Purchases of non-marketable securities              --             --             --        (15,000)            --        (15,000)
  Investments in unconsolidated affiliates       (15,089)            --       (221,484)           (24)       236,597             --
  Cash paid for acquisitions of
    businesses, net                                   --             --             --       (135,652)            --       (135,652)
  Capital expenditures                                --             --             --       (326,536)            --       (326,536)
  Cash paid for other current assets                  --             --             --         (8,725)            --         (8,725)
  Proceeds from sales of assets and
   insurance claims                                   --             --             --         34,877             --         34,877
                                             -----------    -----------    -----------    -----------    -----------    -----------
NET CASH USED FOR INVESTING ACTIVITIES           (40,144)            --       (221,505)      (629,234)       236,597       (654,286)
                                             -----------    -----------    -----------    -----------    -----------    -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Decrease in cash overdrafts                         --             --             --         (3,658)            --         (3,658)
  Decrease in restricted cash                         --             --             --            210             --            210
  Decrease in short-term borrowings, net              --             --             --           (844)            --           (844)
  Proceeds from long-term debt                        --        272,765        223,139             --             --        495,904
  Reduction of long-term debt                         --         (5,047)            --        (25,784)            --        (30,831)
  Debt issuance costs                                 --         (1,634)        (1,311)            --             --         (2,945)
  Proceeds from issuance of common shares          4,522          8,328             --             --             --         12,850
  Proceeds from parent contributions                  --             --             12        236,585       (236,597)            --
  Repurchase of common shares                     (2,486)            --             --             --             --         (2,486)
  Cash Dividends paid                                 --        (81,263)            --             --         81,263             --
  Payments related to cash flow hedges                --         (1,494)            --             --             --         (1,494)
                                             -----------    -----------    -----------    -----------    -----------    -----------
NET CASH PROVIDED BY FINANCING ACTIVITIES          2,036        191,655        221,840        206,509      (155,334)       466,706
                                             -----------    -----------    -----------    -----------    -----------    -----------
EFFECT OF EXCHANGE RATE CHANGES ON CASH
  AND CASH EQUIVALENTS                                --             --             --          2,312             --          2,312
                                             -----------    -----------    -----------    -----------    -----------    -----------
NET INCREASE (DECREASE) IN CASH AND
  CASH EQUIVALENTS                                40,127         (2,163)           207        177,437             --        215,608
                                             -----------    -----------    -----------    -----------    -----------    -----------
CASH AND CASH EQUIVALENTS, BEGINNING
  OF PERIOD                                           --          2,201             --        196,242             --        198,443
                                             -----------    -----------    -----------    -----------    -----------    -----------
CASH AND CASH EQUIVALENTS, END
  OF PERIOD                                  $    40,127    $        38    $       207    $   373,679    $        --    $   414,051
                                             -----------    -----------    -----------    -----------    -----------    -----------
</Table>



<Table>
<Caption>
                                                                     YEAR ENDED DECEMBER 31, 2001
                                            -----------------------------------------------------------------------------------
(IN THOUSANDS)                                              NABORS                       OTHER
                                               NABORS      DELAWARE        NABORS     SUBSIDIARIES
                                              (PARENT/     (ISSUER/       HOLDINGS        (NON-      CONSOLIDATING  CONSOLIDATED
                                             GUARANTOR)   GUARANTOR)      (ISSUER)     GUARANTORS)    ADJUSTMENTS      TOTAL
                                            -----------   -----------    -----------   -----------    -----------   -----------
<S>                                         <C>           <C>            <C>          <C>            <C>            <C>
NET CASH (USED FOR) PROVIDED BY
  OPERATING ACTIVITIES                      $        --   $  (447,834)   $        --   $ 1,151,973    $        --   $   704,139
                                             -----------    -----------    ----------- -----------    -----------    -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Purchases of marketable
    securities, available-for-sale                   --            --             --      (804,067)            --      (804,067)
  Sales of marketable securities,
    available-for-sale                               --            --             --       431,498             --       431,498
  Cash paid for acquisition of
    businesses, net                                  --            --             --       (66,352)            --       (66,352)
  Capital expenditures                               --            --             --      (712,605)            --      (712,605)
  Proceeds from sales of assets
    and insurance claims                             --            --             --        15,067             --        15,067
                                            -----------   -----------    -----------   -----------    -----------   -----------
NET CASH USED FOR INVESTING ACTIVITIES               --            --             --    (1,136,459)            --    (1,136,459)
                                            -----------   -----------    -----------   -----------    -----------   -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Increase in cash overdrafts                        --            --             --         2,395             --         2,395
  Decrease in restricted cash                        --            --             --           692             --           692
  Proceeds from long-term debt                       --       840,338             --            --             --       840,338
  Reduction of long-term debt                        --      (139,798)            --       (16,203)            --      (156,001)
  Debt issuance costs                                --       (12,879)            --            --             --       (12,879)
  Proceeds from issuance of common shares            --         8,219             --            --             --         8,219
  Repurchase of common shares                        --      (247,963)            --            --             --      (247,963)
                                            -----------   -----------    -----------   -----------    -----------   -----------
NET CASH PROVIDED BY (USED FOR)
  FINANCING ACTIVITIES                               --       447,917             --       (13,116)            --       434,801
                                            -----------   -----------    -----------   -----------    -----------   -----------
EFFECT OF EXCHANGE RATE CHANGES ON CASH
  AND CASH EQUIVALENTS                               --            --             --        (1,350)            --        (1,350)
                                            -----------   -----------    -----------   -----------    -----------   -----------
NET INCREASE IN CASH AND CASH EQUIVALENTS            --            83             --         1,048             --         1,131
CASH AND CASH EQUIVALENTS, BEGINNING
  OF PERIOD                                          --         2,118             --       195,194             --       197,312
                                            -----------   -----------    -----------   -----------    -----------   -----------
CASH AND CASH EQUIVALENTS, END OF PERIOD    $        --   $     2,201    $        --   $   196,242    $        --   $   198,443
                                            -----------   -----------    -----------   -----------    -----------   -----------
</Table>



                                  nbr (106-107)



<PAGE>
                             CORPORATE INFORMATION

                    (NABORS INDUSTRIES LTD. AND SUBSIDIARIES)


CORPORATE ADDRESS
Nabors Industries Ltd.
2nd Floor International Trading Center
Warrens
P.O. Box 905E
St. Michaels, Barbados
Telephone: (246) 421-9471
Fax: (246) 421-9472

FORM 10-K

Copies may be obtained at no charge by writing to our Corporate Secretary at
Nabors' corporate office.

TRANSFER AGENT
EquiServe
P.O. Box 43069
Providence, Rhode Island 02940-3069

INVESTOR RELATIONS
Dennis A. Smith
Director of Corporate Development

INDEPENDENT AUDITORS
PricewaterhouseCoopers LLP
Houston, Texas

PRICE OF COMMON SHARES

     As of December 31, 2003, there were 146,656,432 shares of common shares
outstanding held by 2,241 holders of record.

     The common shares are listed on the American Stock Exchange under the
symbol "NBR". The following table sets forth the reported high and low sales
prices of the common shares on the Composite Tape for the calendar quarters
indicated.

<Table>
<Caption>
                                STOCK PRICE
                          -----------------------
CALENDAR YEAR                 HIGH         LOW
<S>                       <C>          <C>
2001     First quarter    $    62.51   $    51.00
         Second quarter        60.41        37.20
         Third quarter         36.65        18.66
         Fourth quarter        35.73        20.66
                          ----------   ----------

2002     First quarter         42.88        27.05
         Second quarter        48.70        35.30
         Third quarter         36.50        26.52
         Fourth quarter        38.86        30.60
                          ----------   ----------

2003     First quarter         42.60        32.20
         Second quarter        45.85        37.65
         Third quarter         40.50        33.87
         Fourth quarter        42.52        35.76
                          ----------   ----------
</Table>
<PAGE>
                             OFFICERS AND DIRECTORS

                   {NABORS INDUSTRIES LTD. AND SUBSIDIARIES}


<Table>
<S>                                                <C>
OFFICERS                                           JAMES L. PAYNE
                                                   Chairman, Chief Executive Officer and President,
EUGENE M. ISENBERG                                 Nuevo Energy Company
Chairman and Chief Executive Officer
                                                   HANS W. SCHMIDT
ANTHONY G. PETRELLO                                Former Director,
Deputy Chairman, President and                     Deutag Drilling
 Chief Operating Officer
                                                   MYRON M. SHEINFELD
DANIEL MCLACHLIN                                   Senior Counsel,
Vice President - Administration and                Akin, Gump, Straus, Hauer & Feld, L.L.P.
Corporate Secretary
                                                   JACK WEXLER
BRUCE P. KOCH                                      International Business Consultant
Vice President and Chief Financial Officer
                                                   MARTIN J. WHITMAN
DIRECTORS                                          Director,
                                                   Danielson Holding Corporation
EUGENE M. ISENBERG
Chairman and Chief Executive Officer,              Chairman,
Nabors Industries Ltd.                             Third Avenue Trust

ANTHONY G. PETRELLO
Deputy Chairman, President and
 Chief Operating Officer
Nabors Industries Ltd.
</Table>

              PRINCIPAL OPERATING SUBSIDIARIES AND LEAD EXECUTIVES

<Table>
<S>                                                <C>
NABORS ALASKA DRILLING, INC.                       NABORS MANAGEMENT LTD.
Anchorage, Alaska                                  NABORS DRILLING INTERNATIONAL LIMITED
James Denney                                       NABORS DRILLING INTERNATIONAL II LIMITED
                                                   SUNDOWNER OFFSHORE INTERNATIONAL
NABORS CANADA L.P.                                   (BERMUDA) LIMITED
Calgary, Alberta                                   Hamilton, Bermuda
Duane A. Mather                                    Siegfried Meissner

NABORS DRILLING USA, LP                            NABORS OFFSHORE CORPORATION
PEAK USA ENERGY SERVICES, LTD.                     Houston, Texas
RAMSHORN INVESTMENTS, INC.                         Jerry C. Shanklin
Houston, Texas
Larry P. Heidt                                     CANRIG DRILLING TECHNOLOGY LTD.
                                                   Magnolia, Texas
POOL WELL SERVICES CO. AND                         Christopher P. Papouras
POOL COMPANY TEXAS, LTD.
Houston, Texas                                     EPOCH WELL SERVICES, INC.
James Denney                                       Houston, Texas
                                                   Christopher P. Papouras
RYAN ENERGY TECHNOLOGIES
Calgary, Alberta                                   PEAK OILFIELD SERVICE COMPANY
Richard Ryan                                       Anchorage, Alaska
                                                   Michael R. O' Connor

                                                   SEA MAR, A DIVISION OF POOL WELL SERVICES CO.
                                                   Houston, Texas
                                                   Van Dewitt
</Table>



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-14
<SEQUENCE>9
<FILENAME>h13476exv14.txt
<DESCRIPTION>CODE OF ETHICS
<TEXT>
<PAGE>
                                                                      EXHIBIT 14










                            CODE OF BUSINESS CONDUCT



                             NABORS INDUSTRIES LTD.
                              AND ITS SUBSIDIARIES




                                    MAY 2003

<PAGE>
                                    FOREWORD

Nabors prides itself in being the industry leader in all aspects of its
business. Leadership includes maintaining high moral, ethical and legal
standards in all relationships and transactions in which the Company engages. To
reaffirm these principles, the Board of Directors has adopted the following Code
of Business Conduct, which applies to all directors, officers and employees of
the Company and its subsidiaries.

The guidelines contained in the Code are of necessity broad. Furthermore, the
laws and regulations applicable to many of the matters addressed in the Code are
complex and subject to change. Questions about the Code's application to
specific circumstances should be directed to an employee's supervisor, Human
Resources Department or the Law Department. When in doubt about an ethics
question, ask before you act.

Whether you are a new employee or one who has been with the Company for some
time, I urge you to familiarize yourself with the Code of Business Conduct.
Employees will be required to certify compliance with the Code on an annual
basis. More importantly, employees are expected to conform to the principles of
honesty and integrity embodied in the Code every day and in every way.

/s/ Eugene M. Isenberg
----------------------
Eugene M. Isenberg
Chairman & Chief Executive Officer
<PAGE>
                                TABLE OF CONTENTS

INTRODUCTION                                                            1

FINANCIAL INTEGRITY                                                     1

CONFLICTS OF INTEREST                                                   3

COMPLIANCE WITH LAWS, RULES & REGULATIONS
   Fair Competition                                                     4
   Insider Trading                                                      5
   Health, Safety & Environment                                         5
   Fair Employment Practices                                            5
   Political Activities                                                 6

INTERNATIONAL BUSINESS
   Working with Governments                                             7
   Improper Payments                                                    7
   Export Controls/U.S. Embargos/Trade Sanctions                        8

INTELLECTUAL PROPERTY AND CONFIDENTIAL INFORMATION                      9

COMPLIANCE AND REPORTING
   Employee Responsibilities                                           10
   Management Responsibilities                                         11
   Expressing Your Personal Commitment                                 11


THIS CODE OF BUSINESS CONDUCT AND THE POLICIES DESCRIBED IN IT DO NOT ALTER THE
AT-WILL NATURE OF ANY EMPLOYMENT RELATIONSHIP AND DO NOT CREATE ANY CONTRACTUAL
RIGHTS OR ENLARGE ANY LEGAL RIGHTS OF ANY EMPLOYEE OR THIRD PARTY.
<PAGE>
                                  INTRODUCTION

This Code of Business Conduct ("Code") embodies the commitment of Nabors
Industries Ltd. and its subsidiaries ("Nabors" or the "Company") to conduct our
business in accordance with applicable laws and high ethical standards. All
employees and directors of Nabors throughout the world are expected to adhere to
the principles described in this Code. We also expect consultants and agents we
retain generally to abide by this Code.

The Code should be read in conjunction with the safety, human resource,
accounting, legal and other policies (collectively, "Policies") applicable to an
employee, which Policies are not part of this Code.

                               FINANCIAL INTEGRITY

The Company expects candor from employees at all levels and full compliance with
Nabors' accounting Policies and controls. Our Board of Directors and senior
management do care how results are obtained, not just that they are obtained.
The Company will not tolerate employees who achieve results at the cost of
violation of laws or who deal unscrupulously.

Nabors' shareholders, creditors, management, governmental entities, and your
co-workers each rely upon the accuracy and transparency of the Company's
accounting records. It is imperative that the accounting records and reports
produced from them accurately and fairly reflect the assets, liabilities,
expenses and revenues of the Company in accordance with applicable laws and
accounting standards.

Accurate documentation in reasonable detail must support all transactions. False
or misleading accounting records, transactions, books and reports (including
expense reports and time sheets) are strictly prohibited. Misclassification of
transactions as to accounts, business units, or accounting periods is forbidden.
Each employee bears responsibility for ensuring that they are not party to a
false or misleading accounting entry.

All payments by the Company for goods or services should be described accurately
and fairly in the Company's financial records, should be supported by
contemporaneous documentation, and must be made only for the purposes described
in the documents and records supporting the payment.

Maintaining secret or unrecorded Company funds or bank accounts is strictly
prohibited. All cash received by the Company shall be promptly recorded in the
Company's financial records and deposited in an account maintained with a bank
or other financial institution approved by Nabors' Treasurer.

Employees participating in an accounting function should familiarize themselves
with and follow Nabors' General Accounting Procedures (GAP), as well as all
generally accepted accounting principles (GAAP), standards, laws and regulations
for accounting and financial reporting of transactions, estimates and forecasts.
Accruals shown in the Company's accounting records (e.g., allowance for
uncollectible receivables, prepaid expenses, and accrued expenses) shall be
supported by appropriate documentation and based upon good faith estimates as
required by GAP and GAAP.

                                       1
<PAGE>
Employees should give complete and accurate information in response to any
inquiry from Nabors' internal auditors and outside independent auditors, as well
as the Company's legal counsel.

THINGS TO WATCH OUT FOR

o   Failure to obtain appropriate approvals for capital expenditures;

o   Financial results that seem inconsistent with underlying performance;

o   Inaccurate financial records, such as overstated expense reports, or
    erroneous time sheets or invoices;

o   Transactions that are inconsistent with good business economics;

o   Absence of controls to protect assets from risk of loss;

o   Circumventing review and approval procedures;

o   Adequacy of routines and controls at newly acquired businesses and at
    remote, thinly staffed sites;

o   Requests not to disclose information to accounting or management personnel;

o   Unreasonable delays in recording transactions.

                                       2
<PAGE>
                              CONFLICTS OF INTEREST

Nabors recognizes and respects that employees may take part in legitimate
financial, business and other activities outside their jobs. However, those
activities must be lawful and free of conflicts with their responsibilities as
Nabors employees. Unless specific other arrangements are made, all employees are
expected to work a full-time schedule. To avoid any actual or perceived conflict
of interest, employees should inform their supervisor of any outside employment,
directorship, or business involvement that might reasonably be perceived as
creating a conflict now or in the future.

Conflicts of interest are prohibited as a matter of policy, unless proper
approvals have been obtained. In particular, employees must not exploit their
position with or relationships developed through Nabors for personal gain.
Accordingly, you should not accept gifts, gratuities or anything else of value
from a third party, except as permitted under Company Policies. Misuse of
Nabors' equipment or resources, intellectual property, confidential information,
time or facilities (including office equipment, e-mail, and computer
applications) can also constitute an impermissible conflict of interest.

THINGS TO WATCH OUT FOR

o   Taking a part-time job where you may be tempted to spend time on that job
    during your normal Nabors working hours or to use Nabors equipment or
    materials;

o   Receiving gifts of greater than nominal value from suppliers, customers or
    competitors while you are in a position to influence Nabors decisions that
    might affect or appear to affect the outside concern;

o   Receiving personal discounts or other benefits from suppliers, service
    providers or customers not available to the general public or similarly
    situated Nabors employees.

o   Directing business to a supplier that is owned or managed by a relative or
    close friend;

o   Misusing Nabors resources, your position or influence to promote or assist
    an outside business;

o   Preferential hiring of, direct supervision of, or making a promotion
    decision about a spouse, relative or close personal friend;

o   A romantic or other personal relationship that may create a conflict of
    interest;

o   Owning a significant interest in a supplier, competitor or customer.

For a related-party transaction involving an officer or director of the Company,
prior written approval of the Audit Committee is required. For a related-party
transaction involving any other employee, prior written approval of the
President or Chief Executive Officer of the Company is required.

                                       3
<PAGE>
                  COMPLIANCE WITH LAWS, RULES & REGULATIONS

It is Nabors' policy to comply with all applicable laws, rules and regulations.
It is the personal responsibility of each employee and director to adhere to the
standards and restrictions imposed by those laws, rules, and regulations.
Following is a brief summary of certain topics about which employees should be
aware. More detailed descriptions of these laws and Nabors' compliance
requirements can be found in Nabors' Policies.

FAIR COMPETITION

The United States and many other countries regulate and in certain cases
prohibit certain types of anticompetitive behavior. Representation agreements,
patent, copyright and trademark licenses, territorial restrictions on resellers,
rebates, and discounts to customers are several of the subjects which may be
covered by the competition laws of many countries.

Nabors is dedicated to compliance with laws governing fair competition in all of
its activities. Any activity that undermines this commitment is unacceptable.
Accordingly, all purchases and sales must be predicated strictly on
considerations of efficiency, price, quality, service and suitability.

THINGS TO WATCH OUT FOR

The laws governing this area are complex, and employees should seek counsel
whenever appropriate.

Following are some guidelines for certain sensitive areas:

    o   Do not discuss, communicate (including at industry meetings or in
        surveys), propose or enter into any agreements or understandings --
        express or implied, formal or informal, written or oral -- with any
        competitor regarding:

        o   prices;

        o   terms or conditions of sale;

        o   wages, compensation or benefits information;

        o   costs, profits or profit margins;

        o   product or service offerings;

        o   production or sales capacity or volume;

        o   market share;

        o   coordination of bidding activities;

        o   dividing sales territories or allocation of customers or product
            lines;

    o   Consult with the Law Department early in the process of evaluating any
        proposed merger, acquisition, or joint venture;

    o   Consult with the Law Department in connection with business arrangements
        that could raise antitrust issues, including exclusive arrangements for
        the purchase or sale of products or services and bundling of goods and
        services;

                                       4
<PAGE>
INSIDER TRADING

Generally, it is both illegal and against Nabors' policy for any employee or
director who is aware of material nonpublic information relating to the Company
to buy or sell any securities of the Company or recommend that another person
buy, sell, or hold the securities of the Company.

More detailed rules governing the trading of Company securities by employees is
contained in the Policies. Any employee who is uncertain about the legal rules
governing his or her purchase or sale of Company securities (including the
exercise of employee stock options) should consult with Nabors' Corporate
Secretary or Nabors' Law Department before making any such purchase or sale.

HEALTH, SAFETY & ENVIRONMENT

Nabors is committed to health, safety and environmental (HSE) excellence.
Compliance with all applicable laws, rules and regulations governing health,
safety and the environment is a responsibility of management and employees in
all functions.

Continuous improvement in its HSE programs is a core business strategy of
Nabors. No deviations from Company safety practices and procedures are permitted
without the approval of appropriate Company personnel or governmental regulatory
agency. Disposal of waste in violation of applicable laws, regulations, or
Company Policies, as well as the concealment, destruction, or falsification of
records, is strictly forbidden.

Each business unit has issued its own HSE Policies. Employees are expected to
strictly comply with these Policies, and supervisors are expected to strictly
enforce these Policies.

THINGS TO WATCH OUT FOR

o   Unsafe activities and conditions, such as failure to use prescribed personal
    protective equipment or unjustified departures from applicable HSE policies;

o   Failure to comply with health, safety or environmental regulations and
    procedures;

o   HSE complaints from employees, customers or others;

o   Deficiencies noted by government inspectors;

o   Unreported health, safety or environmental hazards or accidents;

o   Concerns about possible product safety issues;

o   Possession, use, purchase, or sale of alcohol or illegal drugs, or persons
    under the influence of alcohol or illegal drugs on Company premises or while
    performing work for the Company outside Company premises.

FAIR EMPLOYMENT PRACTICES

Nabors is committed to provide equal employment opportunity and to follow
applicable labor and employment laws wherever it operates, including the
prohibition against all forms of illegal discrimination. This includes observing
those laws that pertain to freedom of association, privacy, recognition of the
right to engage in collective bargaining, and those laws that pertain to the
elimination of any improper employment discrimination or harassment. By
providing equal access and fair treatment to all employees on the basis of
merit, we improve Nabors' success

                                       5
<PAGE>
while enhancing the progress of individuals and the communities where our
businesses are located.

THINGS TO WATCH OUT FOR

o   Harassment of an individual or group of individuals in the workplace (for
    example, telling offensive jokes or displaying materials that ridicule or
    offend a member of a particular race, gender, or ethnic group);

o   Allowing race, color, religion, national origin, gender, age, disability,
    veteran status or other characteristic protected by applicable law to be a
    factor in hiring, firing, promotion, compensation, or other
    employment-related decisions;

o   Making unwelcome sexual advances;

o   Violating a labor law in the country of operation;

o   Refusing to work, or otherwise cooperate with, certain individuals because
    of their race, religion, sex, or other protected status;

o   Terminating an employee without following appropriate procedures;

o   Disclosing employment, personal or medical data to a person who does not
    have the business need, authority or the subject's consent;

o   Intimidating or discriminating against employees for engaging in collective
    bargaining activities.

POLITICAL ACTIVITIES

Nabors does not make contributions to political candidates or political parties
except as permitted by applicable law.

Employees engaging in political activity will do so as private citizens and not
as representatives of Nabors. An employee's personal lawful political
contribution, or decision not to make contributions, will not influence the
employee's compensation, job security, or opportunities for advancement.

                                       6
<PAGE>
                             INTERNATIONAL BUSINESS

WORKING WITH GOVERNMENTS

Nabors conducts business with many national governments (including
government-owned enterprises). Nabors also interacts with many government
agencies, ministries, officials, and public international agencies. Nabors is
committed to conducting its business with all governmental representatives with
high ethical standards and in compliance with applicable laws and regulations,
including U.S. laws that have application outside of U.S. territories, and
special requirements associated with government transactions.

THINGS TO WATCH OUT FOR

o   Violating applicable laws or regulations that establish gratuity
    restrictions, entertainment rules, recruiting prohibitions or certification
    procedures;

o   Acceptance of information related to the government's competitive selection
    of a supplier, or a competitor's bid, unless the appropriate representative
    has specifically and lawfully authorized release of such information.

IMPROPER PAYMENTS

Bribery of public and private officials in the conduct of Nabors' business in
the United States and abroad is strictly prohibited. Employees should not,
directly or indirectly, offer anything of value to a government official,
government employee or customer for the purpose of influencing any act or
decision of the official or employee in their official capacity or inducing such
person to do or omit to do any act in violation of their lawful or ethical duty.
Nabors policy in this regard extends to payments to consultants, agents or other
intermediaries when a Nabors employee knows or has reason to believe that some
part of a payment will be used to bribe or otherwise influence a public official
or customer.

Violations of this policy can result in severe civil and criminal penalties. If
you are confronted with a demand for a bribe from anyone, you should report it
to your supervisor and the Law Department. More detailed rules governing
improper payments can be found in the Policies.

THINGS TO WATCH OUT FOR

o   Anyone representing or being considered to represent Nabors who has been
    accused of improper business practices; has influence on the buying decision
    and a reputation for bribes; has a family or other relationship that could
    improperly influence the decision of a customer or government official;
    approaches you near an award decision and explains that he or she has a
    "special arrangement" with a government official or the customer; or insists
    on receiving a commission payment before the announcement of the award
    decision;

o   Any request that a commission or other payment be made in a third country or
    to another name;

o   A commission that seems large in relation to the services provided.

                                       7
<PAGE>
EXPORT CONTROLS/U.S. EMBARGOS/TRADE SANCTIONS

Many countries regulate international trade transactions, such as imports,
exports and international financial transactions, for a variety of reasons,
including national security and foreign policy. In addition, the United States
prohibits any cooperation with trade boycotts against countries friendly to the
United States or against firms which may be "blacklisted" by certain groups or
countries.

You should follow relevant international trade control regulations, including
licensing, shipping documentation, import documentation, reporting and records
retention requirements of all countries in which you conduct business. In some
cases, these restrictions will apply to international trade in goods,
technology, software, and services as well as to financial transactions.

All information furnished in connection with exports must be accurate and
truthful, including information relating to the value of the exports and the
ultimate destination or use of the exported items. This applies regardless of
whether the information is given to a governmental authority, a co-worker, or a
third party assisting the Company in facilitating the export.

From time to time, the United States prohibits or restricts trade and other
commercial dealings between U.S. citizens and certain countries, persons or
groups. It is imperative that employees seek advice from appropriate personnel
if they have any questions about whether a particular transaction is permissible
under applicable law. Violations of these laws can result in substantial fines
and/or imprisonment for violators.

THINGS TO WATCH OUT FOR

o   Unfamiliar customers or vendors without convincing references;

o   Evasive, reluctant or otherwise unsatisfactory answers by a customer to
    questions about end use, end user, delivery dates or delivery locations;

o   Freight forwarder listed as ultimate consignee;

o   Transactions involving an embargoed country, a citizen or representative of
    an embargoed country or an individual or entity subject to government
    sanction;

o   Any payment to the exporter or benefiting the exporter that is not included
    in the invoice price or otherwise reported to customs authorities;

o   Any payments or transactions with entities listed on the Specially
    Designated Nationals and Blocked Persons List promulgated by the U.S.
    Treasury's Office of Foreign Assets Control.

                                       8
<PAGE>
               INTELLECTUAL PROPERTY AND CONFIDENTIAL INFORMATION

Among Nabors' most valuable assets is its intellectual property - patents, trade
secrets, trademarks, copyrights and other proprietary information. It is Nabors'
policy to establish, protect, maintain and defend its rights in all commercially
significant intellectual property and to use those rights in responsible ways.
All employees must take steps to safeguard these assets. In addition to
protecting Nabors' intellectual property rights, Nabors respects the valid
intellectual property rights of others. Unauthorized use of the intellectual
property rights of others may expose Nabors to civil lawsuits and damages and is
prohibited.

THINGS TO WATCH OUT FOR

o   Receiving from an employee proprietary information about his or her prior
    employer;

o   Accepting proprietary information from an outsider, without first consulting
    company legal counsel, under circumstances where a confidential relationship
    exists or may be implied;

o   Discussing Nabors' proprietary information with customers or suppliers;

o   Using trademarks and copyrighted information without proper identifying
    marks.

                                       9
<PAGE>
                            COMPLIANCE AND REPORTING

Through leadership at all levels, we want to sustain a culture where ethical
conduct is recognized, valued and exemplified by all employees, officers and
directors. Employees and directors should identify and raise potential issues
before they lead to problems and should ask about application of this Code
whenever in doubt. Any employee or director who becomes aware of any existing or
potential violation of this Code should promptly notify an appropriate person in
management. The Company will take such action as it deems appropriate to address
any existing or potential violations of the Code.

EMPLOYEE RESPONSIBILITIES

You should have a basic understanding of issues covered by each Nabors Policy,
and you should have a detailed understanding of Policies that apply to your job.
Check the Nabors Intranet at www.naborsnet.nabors.com for the complete and
latest text of every Nabors policy that relates to your work.

You should seek assistance from your immediate supervisor, another senior
officer, the President of your organization or the Nabors Law Department when
you have questions about application of the Policies.

You should promptly raise any concern, that you or others may have about
possible violations of this Code or any Nabors Policy. In some circumstances, a
waiver of a policy may be warranted. It is important to identify issues, though,
to avoid misunderstandings and inadvertent violations of law or policy.
Sometimes it may seem difficult to raise a concern. Not raising a concern,
however, can cause tremendous harm, such as:

o   Serious damage to the health, safety and well-being of yourself, your fellow
    employees, the Company as a whole, our customers and the communities in
    which we operate;

o   The loss of confidence in Nabors - by customers, shareholders, governments
    and the public;

o   Fines, damage awards and other financial penalties against the Company;
    fines and/or prison sentences for individual employees.

Those are the reasons the company requires that employees not sit silently when
they have a policy concern. The point of raising a concern is not to get a
friend in trouble, but to protect oneself or others from potential harm.

You should understand the many options you have for raising policy concerns. You
may raise them with a Nabors manager or, if you prefer, with company human
resource personnel, the Law Department, or an internal or independent auditor.
Alternatively, you may provide information in confidence by calling the Nabors
Hotline, established specifically for reporting policy concerns, at
1-877-NABORS7. Your communication may be written or oral, and it may be
anonymous.

If you raise a policy concern and the issue is not resolved, raise it again with
one of the other contacts listed above.

NABORS STRICTLY PROHIBITS ANY EMPLOYEE FROM RETALIATING OR TAKING ADVERSE
ACTION AGAINST ANYONE FOR RAISING OR HELPING TO RESOLVE A POLICY CONCERN.

                                       10
<PAGE>
MANAGEMENT RESPONSIBILITIES

The obligations of Nabors managers go beyond those required of all employees.
Managers in our company are expected to:

o   BUILD AND MAINTAIN A CULTURE OF COMPLIANCE by exemplifying ethical conduct
    in business transactions, communicating that business results are never more
    important than compliance, and encouraging employees to raise their
    integrity questions and concerns.

o   PREVENT COMPLIANCE PROBLEMS by ensuring that policies and procedures,
    tailored to the particular risk areas faced by a business, are issued and
    well-communicated, to ensure that employees understand the requirements of
    this Code, Nabors Policies and applicable law.

o   DETECT COMPLIANCE PROBLEMS by implementing appropriate control measures in
    business processes to detect compliance risks and/or violations and by
    ensuring that periodic compliance reviews are conducted, with the assistance
    of the Corporate Audit Staff, to assess the effectiveness of compliance
    measures and to identify ways of improving them.

o   RESPOND TO COMPLIANCE PROBLEMS by taking prompt corrective action to fix any
    identified weaknesses in compliance measures, taking appropriate
    disciplinary action and consulting with Nabors' legal counsel and making
    appropriate disclosures to regulators and law enforcement authorities.

EXPRESSING YOUR PERSONAL COMMITMENT

Periodically, Nabors asks employees to acknowledge their commitment to and
certify their compliance with this Code and Nabors Policies. Newly hired
employees must also acknowledge and commit to these policies. Each business unit
has a procedure for distributing and collecting these acknowledgments. The
Company expects employees to take these certifications seriously and to make
full disclosure of any issues raised by the certification forms.

Violation of a Nabors policy can also mean breaking the law, subjecting you or
the company to criminal penalties (fines or jail sentences) or civil sanctions
(damage awards or fines).

One final note. Covering up mistakes, whether your own or someone else's,
generally only makes a situation worse. Instead, errors or problems should
immediately be fully disclosed and corrected.

                                       11

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21
<SEQUENCE>10
<FILENAME>h13476exv21.txt
<DESCRIPTION>SIGNIFICANT SUBSIDIARIES
<TEXT>
<PAGE>
                                                                               .
                                                                               .
                                                                               .
                                                                      EXHIBIT 21

                             NABORS INDUSTRIES LTD.
                            SIGNIFICANT SUBSIDIARIES
                             AS OF DECEMBER 31, 2003

<Table>
<Caption>

Subsidiary                                                  Jurisdiction
----------                                                  ------------
<S>                                                         <C>
Nabors Alaska Drilling Inc                                  Alaska
Nabors Corporate Services, Inc.                             Delaware
Nabors Drilling Canada ULC                                  Nova Scotia
Nabors Drilling International Ltd                           Bermuda
Nabors Drilling USA, LP                                     Delaware
Nabors Exchangeco (Canada) Inc                              Canada
Nabors Holding Company                                      Delaware
Nabors Industries Inc.                                      Delaware
Nabors International Finance Inc                            Delaware
Nabors International Holdings Ltd                           Bermuda
Nabors International Inc                                    Delaware
Nabors Management Ltd                                       Bermuda
Nabors Maritime Holdings, Inc                               Delaware
Nabors Offshore Americas S.a.r.L.                           Luxembourg
Nabors Offshore Netherlands B.V.                            Netherlands
Nabors Perforaciones de Mexico S. de R.L. de C.V.           Mexico
Nabors US Finance LLC                                       Delaware
Nova Scotia Company                                         Nova Scotia
Oak Leaf Investments Inc                                    Delaware
PCNV Inc.                                                   Nevada
Pool Company                                                Delaware
Pool Company Texas Ltd.                                     Texas
Pool Well Services Co                                       Delaware
Serendipity Investments Ltd.                                Bermuda
Sundowner Offshore International Ltd                        Bermuda
Yellow Deer Investments Corp                                Nevada
</Table>















</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23
<SEQUENCE>11
<FILENAME>h13476exv23.txt
<DESCRIPTION>CONSENT OF INDEPENDENT ACCOUNTANTS
<TEXT>
<PAGE>
                                                                      EXHIBIT 23



                       CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Registration
Statements on Form S-8 (Registration Statement Nos. 333-96699, 333-92483-99,
333-91829-99, 333-91743-99, 333-87069-99, 333-86289-99, 333-76077-99,
333-45446-99 and 333-11313-99) and on Form S-3 (Registration Numbers
333-107806-01, 333-91296, 333-85228-99, 333-99267 and 333-102246) of Nabors
Industries Ltd. of our report dated March 5, 2004 relating to the financial
statements, which appears in the Annual Report to Shareholders, which is
incorporated in this Annual Report on Form 10-K. We also consent to the
incorporation by reference of our report dated March 5, 2004 relating to the
financial statement schedule, which appears in this Form 10-K.

Houston, Texas
March 15, 2004

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-31.1
<SEQUENCE>12
<FILENAME>h13476exv31w1.txt
<DESCRIPTION>CERTIFICATION OF CEO PURSUANT SECTION 302
<TEXT>
<PAGE>
                                                                    EXHIBIT 31.1

                                  CERTIFICATION

I, Eugene M. Isenberg, Chairman and Chief Executive Officer of Nabors Industries
Ltd., certify that:

1. I have reviewed this annual report on Form 10-K of Nabors Industries Ltd.;

2. Based on my knowledge, this 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 report;

3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

         (a) Designed such disclosure controls and procedures, or caused such
         disclosure controls and procedures to be designed under our
         supervision, to ensure that material information relating to the
         registrant, including its consolidated subsidiaries, is made known to
         us by others within those entities, particularly during the period in
         which this report is being prepared;

         (b) Evaluated the effectiveness of the registrant's disclosure controls
         and procedures and presented in this report our conclusions about the
         effectiveness of the disclosure controls and procedures, as of the end
         of the period covered by this report based on such evaluation; and

         (c) Disclosed in this report any change in the registrant's internal
         control over financial reporting that occurred during the registrant's
         most recent fiscal quarter (the registrant's fourth quarter in the case
         of an annual report) that has materially affected, or is reasonably
         likely to materially affect, the registrant's internal control over
         financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):

         (a) All significant deficiencies and material weaknesses in the design
         or operation of internal control over financial reporting which are
         reasonably likely to adversely affect the registrant's ability to
         record, process, summarize and report financial information; and

         (b) Any fraud, whether or not material, that involves management or
         other employees who have a significant role in the registrant's
         internal control over financial reporting.

Date:  March 15, 2004                 /s/ Eugene M. Isenberg
     ----------------------           ------------------------------------
                                      Eugene M. Isenberg
                                      Chairman and Chief Executive Officer

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-31.2
<SEQUENCE>13
<FILENAME>h13476exv31w2.txt
<DESCRIPTION>CERTIFICATION OF CFO PURSUANT SECTION 302
<TEXT>
<PAGE>
                                                                    EXHIBIT 31.2



                                  CERTIFICATION

I, Bruce P. Koch, Vice President and Chief Financial Officer of Nabors
Industries Ltd., certify that:

1.   I have reviewed this annual report on Form 10-K of Nabors Industries Ltd.;

2.   Based on my knowledge, this 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 report;

3.   Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;

4.   The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

     (a)   Designed such disclosure controls and procedures, or caused such
     disclosure controls and procedures to be designed under our supervision, to
     ensure that material information relating to the registrant, including its
     consolidated subsidiaries, is made known to us by others within those
     entities, particularly during the period in which this report is being
     prepared;

     (b)   Evaluated the effectiveness of the registrant's disclosure controls
     and procedures and presented in this report our conclusions about the
     effectiveness of the disclosure controls and procedures, as of the end of
     the period covered by this report based on such evaluation; and

     (c)   Disclosed in this report any change in the registrant's internal
     control over financial reporting that occurred during the registrant's most
     recent fiscal quarter (the registrant's fourth quarter in the case of an
     annual report) that has materially affected, or is reasonably likely to
     materially affect, the registrant's internal control over financial
     reporting; and

5.   The registrant's other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):

     (a)   All significant deficiencies and material weaknesses in the design or
     operation of internal control over financial reporting which are reasonably
     likely to adversely affect the registrant's ability to record, process,
     summarize and report financial information; and

     (b)   Any fraud, whether or not material, that involves management or other
     employees who have a significant role in the registrant's internal control
     over financial reporting.


Date:  March 15, 2004                        /s/ Bruce P. Koch
      ----------------                       -----------------------------------
                                             Bruce P. Koch
                                             Vice President and Chief Financial
                                             Officer (Principal Financial and
                                             Accounting Officer)



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-32.1
<SEQUENCE>14
<FILENAME>h13476exv32w1.txt
<DESCRIPTION>CERTIFICATION OF CEO & CFO PURSUANT TO SECTION 906
<TEXT>
<PAGE>
                                                                    EXHIBIT 32.1


                            CERTIFICATION PURSUANT TO
                             18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                  SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of Nabors Industries Ltd. (the
"Company") for the period ended December 31, 2003 as filed with the Securities
and Exchange Commission on the date hereof (the "Report"), I, Eugene M.
Isenberg, Chairman and Chief Executive Officer of the Company, and I, Bruce P.
Koch, Vice President and Chief Financial Officer of the Company, each certify,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

    (1)  the Report fully complies with the requirements of Section 13(a) or
         15(d) of the Securities Exchange Act of 1934; and

    (2)  the information contained in the Report fairly presents, in all
         material respects, the financial condition and results of operations of
         the Company.

                                    /s/ EUGENE M. ISENBERG
                                    -------------------------------------------
                                    Eugene M. Isenberg
                                    Chairman and Chief Executive Officer
                                    March 15, 2004



                                    /s/ BRUCE P. KOCH
                                    -------------------------------------------
                                    Bruce P. Koch
                                    Vice President and Chief Financial Officer
                                    March 15, 2004


A signed original of this written statement required by Section 906 of the
Sarbanes-Oxley Act of 2002 has been provided to Nabors Industries Ltd. and will
be retained by Nabors Industries Ltd. and will be furnished to the Securities
and Exchange Commission or its staff upon request.


</TEXT>
</DOCUMENT>
</SUBMISSION>
