CAL DIVE INTERNATIONAL INC - 10-K Annual Report

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

FORM 10-K

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 0-22739

CAL DIVE INTERNATIONAL, INC.
(Exact name of registrant as specified in its charter)

MINNESOTA 95-3409686
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

400 NORTH SAM HOUSTON PARKWAY EAST
SUITE 400
HOUSTON, TEXAS 77060
(Address of Principal Executive Offices) (Zip Code)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(281) 618-0400

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

COMMON STOCK (NO PAR VALUE)
(Title of Class)

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 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. [X] Yes [ ] 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). [X] Yes [ ] No

The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant as of June 30, 2003 was $762,022,087 based
on the last reported sales price of the Common Stock on June 30, 2003, as
reported on the NASDAQ/National Market System.

The number of shares of the registrant's Common Stock outstanding as of
March 10, 2004 was 38,024,298.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement for the Annual Meeting of
Shareholders to be held on May 11, 2004, are incorporated by reference into Part
III hereof.

CAL DIVE INTERNATIONAL, INC. ("CDI") INDEX -- FORM 10-K

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FORWARD LOOKING STATEMENTS

This Annual Report on Form 10-K, or Annual Report, including "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in
Item 7, contains forward-looking statements that involve risks, uncertainties
and assumptions that could cause the results of Cal Dive International, Inc. and
its consolidated subsidiaries ("CDI" or "Cal Dive") to differ materially from
those expressed or implied by such forward-looking statements. All statements,
other than statements of historical fact, are statements that could be deemed
forward-looking statements, including, without limitation, any projections of
revenue, gross margin, expenses, earnings or losses from operations, or other
financial items; any statements of the plans, strategies and objectives of
management for future operations; any statement concerning developments,
performance or industry rankings relating to services; any statements regarding
future economic conditions or performance; any statements of expectation or
belief; and any statements of assumptions underlying any of the foregoing. The
risks, uncertainties and assumptions referred to above include the performance
of contracts by suppliers, customers and partners; employee management issues;
complexities of global political and economic developments; and other risks that
are described herein, including, but not limited to, the items discussed in
"Factors Influencing Future Results and Accuracy of Forward-Looking Statements"
set forth in Item 1 of this Annual Report, and that are otherwise described from
time to time in CDI's reports filed with the Securities and Exchange Commission
after this report. CDI assumes no obligation and does not intend to update these
forward-looking statements.

PART I

ITEM 1. BUSINESS.

OVERVIEW

We are an energy services company, incorporated in the State of Minnesota,
specializing in Marine Contracting (subsea construction and well operations) as
well as providing oil and gas companies with alternatives to traditional
approaches of equity sharing in offshore properties through our Oil & Gas
Production and Production Facilities segments. Operations in the Production
Facilities segment should begin in 2004. We operate primarily in the Gulf of
Mexico, or Gulf, and, since 2002, in the North Sea and the Asia/ Pacific regions
with services that cover the lifecycle of an offshore oil and gas field. We
believe we have a longstanding reputation for innovation in our subsea
construction techniques, equipment design and methods of partnering with
customers. Our diversified fleet of 22 vessels and 25 remotely operated vehicles
(or ROVs) and trencher systems perform services that support drilling, well
completion, intervention, construction and decommissioning projects involving
pipelines, production platforms, risers and subsea production systems. We also
have acquired significant interests in oil and gas properties and a Deepwater
production facility at the Marco Polo field. Our customers include major and
independent oil and gas producers, pipeline transmission companies and offshore
engineering and construction firms.

We have positioned ourselves for work in water depths greater than 1,000
feet, referred to as the Deepwater, by continuing to grow our technically
advanced fleet of dynamically positioned, or DP, vessels, ROVs and the number of
highly experienced support professionals we employ. These DP vessels serve as
advanced work platforms for the subsea solutions that we provide with our
alliance partners, a group of internationally recognized contractors and
manufacturers. Most notably, the Q4000, our Deepwater semi-submersible
multi-service vessel, or MSV, incorporates patented technologies that can
improve Deepwater well completion, intervention and construction economics for
our customers. Availability of the Q4000 and the Seawell, together with our
other large vessels, the Eclipse, Mystic Viking and Intrepid, enable us to offer
a diverse fleet of DP subsea construction and intervention vessels.

Our ROV subsidiary, Canyon Offshore, Inc., or Canyon, offers survey,
engineering, repair, maintenance and international cable burial services in the
Gulf, Europe/West Africa and Asia/Pacific regions. Our wholly owned
subsidiaries, Wells Ops, Inc., and its Aberdeen, Scotland based sister company,
Well Ops (U.K.) Limited, engineer, manage and conduct well construction,
intervention and decommissioning operations in

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water depths from 200 to 10,000 feet in, respectively, the Gulf of Mexico and
the North Sea. Well Ops (U.K.) Limited also performs saturation diving in the
North Sea from its DP vessel, the Seawell.

On the Outer Continental Shelf, or OCS, of the Gulf of Mexico, in water
depths up to 1,000 feet, we perform traditional subsea services, including air
and saturation diving and salvage work. Our shallow water diving division
provides a full complement of services in the shallow water market from the
shore to a depth of 200 feet. We own and operate eleven vessels that are
permanently dedicated to performing traditional diving services. Altogether we
employ more than 600 full-time supervisors, divers, tenders and support staff
who make us the market leader for all manned diving services in the Gulf. In
depths from 200 feet to 1,000 feet, these services are provided by our two
four-point saturation diving vessels, with another five DP vessels capable of
providing such services on the OCS. We provide subsea construction services in
the OCS "spot market" where projects are generally turnkey in nature, short in
duration (two to thirty days), and require the availability of multiple vessels
due to frequent rescheduling. The technical and operational experience of our
personnel and the scheduling flexibility offered by our large fleet enable us to
manage turnkey projects and to meet our customers' requirements. We have also
established a presence in the salvage market by offering customers a number of
options to address their decommissioning obligations in a cost-efficient manner,
particularly the removal of smaller structures.

In our Oil & Gas Production business, our subsidiary Energy Resource
Technology, Inc., or ERT, acquires and produces mature, non-core offshore
property interests, offering customers a cost-effective alternative to the
decommissioning process required by law. In 2003, ERT continued to successfully
pursue its "PUD" strategy of acquiring and developing proved undeveloped, or
PUD, reserves, i.e., leases where the exploratory well had encountered proven
reserves that were judged by the current owner to be too marginal to justify
development. In addition, ERT's reservoir engineering and geophysical expertise
enabled us in 2000 to acquire a working interest in Gunnison, a Deepwater Gulf
oil and natural gas exploration project, in partnership with the operator, Kerr
McGee Oil & Gas Corp., which began initial production in December 2003.

In our Production Facilities segment we participate in the ownership of
production facilities in hub locations where there is potential for significant
Subsea tieback activity. In addition to production from the Gunnison reservoir,
Cal Dive will receive ongoing revenues from its 20% interest in the production
facility as satellite prospects are drilled and tied back to the spar. Deepwater
Gateway, Inc., our second such endeavor, involves a 50% ownership position in
the tension-leg platform installed at Anadarko's Marco Polo field at Green
Canyon block 608. At both Gunnison and Marco Polo, we participated in field
development planning and performed subsea construction work.

BUSINESS STRENGTHS AND STRATEGIES

Our overall corporate goal is to increase shareholder value by
strengthening our market position to provide a return that leads our Peer Group.
Our goal for Return on Invested Capital is 10% or greater. We attempt to achieve
our return on capital objective by focusing on the following business strengths
and strategies.

OUR STRENGTHS

Fleet of DP Vessels. We believe that our fleet of DP construction vessels
is the fourth largest in the world, with one of the most diverse and technically
advanced collections of subsea intervention and construction capabilities. The
comprehensive services provided by our DP vessels are both complementary and
overlapping, enabling us to provide customers with the redundancy essential for
most projects, especially in the Deepwater.

Formation of Well Operations Subsidiary as a "First In"
Advantage. Establishment of the Well Ops group followed the construction of the
purpose-built Q4000 and the acquisition of the Subsea Well Operations Business
Unit of Technip in Aberdeen, Scotland. The mission of these companies is to
provide the industry

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with a single, comprehensive source for addressing current well operations needs
and to engineer for future needs.

Experienced Personnel and Turnkey Contracting. A key element of our
successful growth has been our ability to attract and retain experienced
personnel who are among the best in the industry at providing turnkey
contracting. We believe the recognized skill of our personnel and our successful
operating history uniquely position us to capitalize on the trend in the oil and
gas industry of increased outsourcing to contractors and suppliers.

Major Provider of Marine Construction Services on the OCS. We believe that
our shallow water diving division, and our position in the Gulf for saturation
diving services make us one of the largest supplier of subsea construction
services on the Gulf of Mexico OCS. We expect the aging infrastructure will
require increasing level of IMR.

Oil & Gas Production. The strategy of ERT's oil and gas production
business differentiates us from our competitors and helps to offset the cyclical
nature of our subsea construction operations. Each of ERT's oil and gas
investments is designed to secure utilization of CDI construction vessels. We
successfully applied the ERT model to the Deepwater with our involvement in the
Gunnison field.

Production Facilities. At the Marco Polo field, our 50% ownership in the
production facility will allow us to realize a return on investment consisting
of both a fixed monthly demand charge and a volumetric tariff charge. In
addition, we will assist with the installation of the TLP and work to develop
the surrounding acreage that can be tied back to the platform by our
construction vessels. Our long-term goal is that 40% of all of our construction
utilization is provided by ownership of offshore fields and production
facilities.

Decommissioning Operations. Over the last decade, we have established a
presence in decommissioning offshore facilities, particularly in the removal of
the smaller structures and caissons that make up approximately half of the
structures in the Gulf. We expect demand for decommissioning services to
increase due to the significant backlog of platforms and caissons that must be
removed in accordance with government regulations.

OUR STRATEGIES

Focusing on the Gulf and Global Expansion. We will continue to focus on
the Gulf of Mexico, where we have provided marine construction services since
1975, as well as the North Sea, Southeast Asia and other Deepwater basins
worldwide. We expect oil and gas exploration and development activity in the
Deepwater Gulf and other Deepwater basins of the world to increase over the next
several years.

Capturing a Leading Presence in the Deepwater Market. Our fleet now
includes nine world-class DP vessels, six of which are based in the Gulf of
Mexico. In addition, through Canyon we own and operate 25 ROV and trencher
systems, including a "T750" Super Trencher as well as three Triton XLS ROV
systems to fulfill requirements under a Master Service Agreement entered into
with Technip-Coflexip. Canyon represents an integration that is consistent with
our strategy of controlling key aspects along the critical path of significant
Deepwater projects.

Developing Well Operations Niche. As major and independent oil and gas
companies expand operations in the Deepwater basins of the world, development of
these reserves will often require the installation of subsea trees.
Historically, drilling rigs were usually necessary for subsea well operations to
troubleshoot or enhance production, shift zones or perform recompletions. Three
of our vessels serve as work platforms for well operations services at costs
significantly less than drilling rigs. In the Gulf of Mexico, our multi-service
semi-submersibles, the Q4000 and the Uncle John have set a series of well
operations "firsts" in increasingly deep water without the use of a rig. In the
North Sea the Seawell has provided intervention and abandonment services for
more than 450 North Sea wells since her commissioning in 1987. Competitive
advantages of the CDI vessels stem from their lower operating costs, together
with an ability to mobilize quickly and to maximize productive time by
performing a broad range of tasks for intervention, construction, inspection,
repair and maintenance.

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Acquiring Mature Oil and Gas Properties. Through ERT we have been
acquiring mature or sunset properties since 1992, thereby providing customers a
cost effective alternative to the decommissioning process. In the last eleven
years, we have acquired interests in 90 leases and currently are the operator of
46 of 61 active offshore leases. ERT has been able to achieve a significant
return on capital by efficiently developing acquired reserves, lowering lease
operating expenses, and adding new reserves through exploitation drilling and
well work. Our customers consider ERT a preferred buyer as a result of ERT's
reputation, Cal Dive's financial strength and salvage expertise. As an industry
leader in acquiring mature properties, ERT has a significant flow of potential
acquisitions. At December 31, 2003, ERT's total proved reserves were 149.8 Bcfe,
including 70.9 Bcfe of proved reserves assigned to our ownership position in
Gunnison.

Expanding Ownership in Production Facilities. Along with GulfTerra Energy
Partners L.P., Cal Dive owns 50% of the tension leg production platform
installed at the Marco Polo field, as well as the 20% interest in the spar at
Gunnison. Ownership of these production facilities provide a transmission type
return that does not entail any reservoir or commodity price risk. The Company
plans to seek additional opportunities to invest in such production facilities.

Expanding the PUD Model. We successfully applied the ERT model to the
Deepwater with our involvement in the Gunnison field. The Deepwater Gulf has
seen a significant increase in oil and gas exploration, development, and
production due, in part, to new technologies that reduce operational costs and
risks; the discovery of new, larger oil and gas reservoirs with high production
potential; government deepwater incentives; and increasing demand and prices.
Along with these larger fields are discoveries where the exploratory well has
encountered smaller proven undeveloped reserves that are judged by the current
owner to be too marginal to justify development. In 2004, ERT will continue to
aggressively pursue its strategy of acquiring PUD reserves and develop these
reserves utilizing Cal Dive's assets. Depending upon the water depth,
development of these fields may require state of the art equipment such as the
Q4000, a more specialized asset such as the Intrepid for pipelay, or a
combination of Cal Dive contracting assets.

THE INDUSTRY

The offshore oilfield services industry originated in the early 1950s to
assist companies as they began to explore and develop offshore fields. The
industry has grown significantly since the early 1970s as the domestic oil and
gas industry has increasingly relied upon these fields for new domestic
production. Factors that we believe will benefit the industry in the coming
years include: (i) increasing world demand for oil and natural gas; (ii) a
continued increase in exploration, development, and production in the Deepwater
Gulf and other Deepwater basins of the world; and (iii) an increased demand for
decommissioning services in compliance with MMS regulations as the OCS offshore
oil and gas industry continues to mature.

In response to the oil and gas industry's ongoing migration to the
Deepwater, equipment and vessel requirements have changed. Most vessels
currently operating in the Deepwater Gulf were designed in the 1970s and 1980s
for work in a maximum depth of approximately 1,000 feet. These vessels have been
modified to take advantage of new technologies and now operate in depths up to
4,000 feet. We believe there is demand in the Gulf for new generation vessels,
such as the Q4000 and Intrepid, that are specifically designed to work in water
depths beyond 4,000 feet.

Defined below are certain terms and ideas helpful to understanding the
services we perform in support of offshore development:

Bcfe: Billions of cubic feet equivalent, used to describe oil volumes
converted to their energy equivalent in natural gas as measured in billions
of cubic feet.

Deepwater: Water depths beyond 1,000 feet.

Dive Support Vessel (DSV): Specially equipped vessel that performs
services and acts as an operational base for divers, ROVs and specialized
equipment.

Dynamic Positioning (DP): Computer-directed thruster systems that use
satellite-based positioning and other positioning technologies to ensure
the proper counteraction to wind, current and wave forces
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enabling the vessel to maintain its position without the use of anchors.
Two DP systems (DP-2) are necessary to provide the redundancy required to
support safe deployment of divers, while only a single DP system is
necessary to support ROV operations.

DP-2: Redundancy allows the vessel to maintain position even with
failure of one DP system; required for vessels which support both manned
diving and robotics and for those working in close proximity to platforms.

EHS: Environment, Health and Safety programs to protect the
environment, safeguard employee health and eliminate injuries.

E&P: Oil and gas exploration and production activities.

IMR: Inspection, maintenance and repair activities.

Life of Field Services: Services performed on offshore facilities,
trees and pipelines from the beginning to the economic end of the life of
an oil field, including installation, inspection, maintenance, repair,
contract operations, well intervention, recompletion and abandonment.

MBbl: When describing oil, refers to 1,000 barrels containing 42
gallons each.

Minerals Management Service (MMS): The federal regulatory body having
responsibility for the mineral resources of the United States OCS.

MMcf: When describing natural gas, refers to 1 million cubic feet.

Moonpool: An opening in the center of a vessel through which a
saturation diving system or ROV may be deployed, allowing safe deployment
in adverse weather conditions.

Outer Continental Shelf (OCS): For purposes of our industry, areas in
the Gulf from the shore to 1,000 feet of water depth.

Peer Group: Defined in this Annual Report as comprising Global
Industries, Ltd. (Nasdaq: GLBL), Horizon Offshore, Inc. (Nasdaq: HOFF),
McDermott International, Inc. (NYSE: MDR), Oceaneering International, Inc.
(NYSE: OII), Stolt Offshore SA (Nasdaq: SOSA), Technip-Coflexip (NYSE: TKP)
and Torch Offshore, Inc. (Nasdaq: TORC).

Proved Undeveloped Reserve (PUD): Proved undeveloped oil and gas
reserves that are expected to be recovered from a new well on undrilled
acreage, or from existing wells where a relatively major expenditure is
required for recompletion.

Remotely Operated Vehicle (ROV): Robotic vehicles used to complement,
support and increase the efficiency of diving and subsea operations and for
tasks beyond the capability of manned diving operations.

Saturation Diving: Saturation diving, required for work in water
depths between 200 and 1,000 feet, involves divers working from special
chambers for extended periods at a pressure equivalent to the pressure at
the work site.

Spar: Floating production facility anchored to the sea bed with
catenary mooring lines.

Spot Market: Prevalent market for subsea contracting in the Gulf,
characterized by projects generally short in duration and often of a
turnkey nature. These projects often require constant rescheduling and the
availability or interchangeability of multiple vessels.

Stranded Field: Smaller PUD reservoir that standing alone may not
justify the economics of a host production facility and/or infrastructure
connections.

Subsea Construction Vessels: Subsea services are typically performed
with the use of specialized construction vessels which provide an
above-water platform that functions as an operational base for divers and
ROVs. Distinguishing characteristics of subsea construction vessels include
DP systems, saturation diving capabilities, deck space, deck load, craneage
and moonpool launching. Deck space, deck
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load and craneage are important features of the vessel's ability to
transport and fabricate hardware, supplies and equipment necessary to
complete subsea projects.

Tension Leg Platform (TLP): A floating Deepwater compliant structure
designed for offshore hydrocarbon production.

Trencher or Trencher System: A subsea robotics system capable of
providing post lay trenching, inspection and burial (PLIB) and maintenance
of submarine cables and flowlines in water depths of 30 to 7,200 feet
across a range of seabed and environmental conditions.

Ultra-Deepwater: Water depths beyond 4,000 feet.

MARINE CONTRACTING

We and our alliance partners provide a full range of marine contracting
services in both the shallow water and Deepwater including:

- Exploration. Pre-installation surveys; rig positioning and installation
assistance; drilling inspection; subsea equipment maintenance; well
completion; search and recovery operations.

- Development. Installation of production platforms; installation of
subsea production systems; pipelay support including connecting pipelines
to risers and subsea assemblies; pipeline stabilization, testing and
inspection; cable and umbilical lay and connection.

- Production. Inspection, maintenance and repair of production structures,
risers and pipelines and subsea equipment; well intervention; life of
field support.

- Decommissioning. Decommissioning and remediation services; plugging and
abandonment services; platform salvage and removal; pipeline abandonment;
site inspections.

DEEPWATER CONTRACTING AND WELL OPERATIONS

In 1994, we began to assemble a fleet of DP vessels in order to deliver
subsea services in the Deepwater and Ultra-Deepwater. Today, our fleet consists
of two semi-submersible DP MSVs, the Q4000 and the Uncle John; a dedicated well
operations vessel, the Seawell; an umbilical and rigid pipelay vessel, the
Intrepid; three construction DP DSVs, the Witch Queen, the Mystic Viking, and
the Eclipse; and two ROV support vessels, the Merlin and the Northern Canyon.

Our subsidiary, Canyon Offshore, Inc., operates ROVs and trenchers that are
designed for offshore construction, rather than supporting drilling rig
operations. As marine construction support in the Gulf of Mexico and other areas
of the world moves to deeper waters, ROV systems will play an increasingly
important role. Our vessels add value by supporting deployment of Canyon's ROVs.
We have positioned ourselves to provide our customers with vessel availability
and schedule flexibility to meet the technological challenges of these Deepwater
construction developments in the Gulf and internationally. Our ROVs, including
the three new Triton XLS ROV systems delivered in 2003, operate in three
regions: the Americas (9), Europe/West Africa (5) and Asia Pacific (6). In
addition to the ROVs, Canyon also has five trenchers that operate in the Asia
Pacific (2) and the Europe/West Africa (3) regions, including a state of the art
"T750" Super Trencher.

We assist customers in solving the operational challenges encountered in
Deepwater projects by using methods or technologies we have developed. To
enhance our ability to provide both full field development and life of field
services, we have alliances with other offshore service and equipment providers.
These alliances enable us to offer state-of-the-art products and service while
maintaining our low overhead base. These alliances are:

- Fugro-McClelland Marine Geoscience, Inc. -- Geotechnical coring and
survey

- Schlumberger Limited -- Deepwater downhole services

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Utilization of our Deepwater vessels of 79.6% in 2003 improved from 2002's
utilization of 72.3%. Major projects for the Deepwater Contracting group in 2002
and 2003 included:

The mission of the Well Ops Group (Well Ops Inc. and Well Ops (U.K.)
Limited) is to provide the industry with a single, comprehensive source for
addressing current subsea well operations needs and to engineer for future
needs. Our purpose-built vessels serve as work platforms for subsea well
operations services at costs significantly less than drilling rigs. In the Gulf
of Mexico, the Q4000 and the Uncle John have set a series of "firsts" in
increasingly deep water without the use of a rig including: first "live subsea
well" intervention; first through tubing subsea well decommission; first "live
subsea well" intervention using wireline lubricator; first Deepwater full field
decommission; first re-entry and decommission through horizontal tree; first
removal and recovery of subsea well templates and horizontal trees; first use of
test tree in open water as a lower riser package (LRP); first subsea transfer of
tree from one well to another during decommissioning operations; first use of
coil tubing drilling in subsea decommissioning; first installation of a "storm
choke" as replacement for subsurface safety control valve; all of which utilized
a semi-submersible DP MSV instead of a drilling rig; first to provide and apply
a purpose-built 7 3/8" bore Intervention Riser System; and the first
interventions in 3,900 feet of salt water without use of a rig. The Seawell has
provided intervention and abandonment services on more than 450 North Sea wells
since her commissioning in 1987. One additional advantage is that the Seawell
can undertake saturation diving and construction tasks independently or
simultaneously with the well intervention activities. We believe that the
Seawell sets the standard for the industry in subsea well intervention and
continues to redefine the boundaries of the industry having performed the first
U.K. subsea light intervention using a 7 1/16" subsea lubricator. Competitive
advantages of our vessels stem from their lower operating costs and the ability
to mobilize quickly for multi-well campaigns of work and maximize productive
time by performing a broad range of tasks for intervention, construction,
inspection, repair and maintenance. Well Ops Inc. and Well Ops (U.K.) Limited
also collaborate with leading downhole

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service providers to provide superior, comprehensive solutions to the well
operations challenges faced by our customers. An alliance is currently in place
with Schlumberger to provide these services.

SHELF CONTRACTING

On the OCS, in water depths up to 1,000 feet, we perform traditional subsea
services including air and saturation diving in support of marine construction
activities. Eleven of our vessels are permanently dedicated to performing
traditional diving services, with another five DP vessels capable of providing
such services, on the OCS. Seven of these vessels support saturation diving. In
addition, our highly qualified personnel have the technical and operational
experience to manage turnkey projects to satisfy customers' requirements and
achieve our targeted profitability.

We deliver our services in the shallow water market, from the shore to a
depth of 200 feet, through our shallow water diving division. In addition, our
saturation diving vessels can deliver services in depths up to 1,000 feet.

Since 1989, we have undertaken a wide variety of decommissioning
assignments, mostly on a turnkey basis. We have established a leading position
in the removal of smaller structures, such as caissons and well protectors,
which represent approximately half of the structures in the Gulf.

OIL & GAS PRODUCTION

We formed ERT in 1992 to exploit a market opportunity to provide a more
efficient solution to offshore abandonment, to expand our off-season salvage and
decommissioning activity, and to support full field production development
projects. Through ERT we offer customers the option of selling mature offshore
fields as an alternative to contracting and managing the many phases of the
decommissioning process. The benefits of our strategy are fourfold. First, oil
and gas revenues counteract the volatility in revenues we experience in offshore
construction. Second, in periods of excess capacity, such as in 2002 and 2003,
we have the flexibility to be less dependent on the competitive bid market and
instead focus on negotiated contracts. Third, our oil and gas operations
generate significant cash flow that has partially funded construction and/or
modification of assets such as the Q4000, Intrepid and Eclipse, enabling us to
add technical talent to support our expansion into the new Deepwater frontier.
Finally, a major objective of our investments in oil and gas properties is to
secure the associated marine construction work.

Within ERT we have assembled a team of personnel with experience in
geology, geophysics, reservoir engineering, drilling, production engineering,
facilities management, lease operations and petroleum land management. ERT
generates income in three ways: lowering salvage costs by using our assets,
operating the field more cost effectively, and extending reservoir life through
well exploitation operations. When a company sells an OCS property, they retain
the financial responsibility for plugging and decommissioning if their purchaser
becomes financially unable to do so. Thus, it becomes important that a property
be sold to a purchaser who has the financial wherewithal to perform their
contractual obligations. Although there is significant competition in this
mature field market, ERT's reputation, supported by Cal Dive's financial
strength, have made it the purchaser of choice of many major and independent oil
and gas companies. In addition, ERT's reservoir engineering and geophysical
expertise enabled us in 2000 to acquire a working interest in Gunnison, a
Deepwater Gulf oil and natural gas exploration project, in partnership with the
operator, Kerr-McGee Oil & Gas Corp., which began initial production in December
2003.

The Deepwater Gulf has seen a significant increase in oil and gas
exploration, development, and production due, in part, to new technologies that
reduce operational costs and risks; the discovery of new, larger oil and gas
reservoirs with high production potential; government deepwater incentives; and
increasing demand and prices. Along with these larger fields are discoveries
where the exploratory well has encountered smaller proven undeveloped reserves
that are judged by the current owner to be too marginal to justify development.
In 2004, ERT will continue to aggressively pursue its strategy of acquiring PUD
reserves, and develop these reserves utilizing Cal Dive's assets. Depending upon
the water depth, development of these

9

fields may require state of the art equipment such as the Q4000, a more
specialized asset such as the Intrepid for pipelay, or a combination of Cal Dive
contracting assets.

The table below sets forth information, as of December 31, 2003, with
respect to estimates of net proved reserves and the present value of estimated
future net cash flows at such date, prepared in accordance with guidelines
established by the Securities and Exchange Commission. The Company's estimates
of reserves at December 31, 2003, have been audited by Huddleston & Co., Inc.,
independent petroleum engineers. All of the Company's reserves are located in
the United States. Proved reserves cannot be measured exactly because the
estimation of reserves involves numerous judgmental determinations. Accordingly,
reserve estimates must be continually revised as a result of new information
obtained from drilling and production history, new geological and geophysical
data and changes in economic conditions.

- ---------------

* The standardized measure of discounted future net cash flows attributable to
our reserves was prepared using constant prices as of the calculation date,
discounted at 10% per annum. As of December 31, 2003, we owned an interest in
288 gross (256 net) oil wells and 151 gross (91 net) natural gas wells located
in federal offshore waters in the Gulf of Mexico.

PRODUCTION FACILITIES

There are over 100 discoveries in the Deepwater Gulf that have yet to be
brought into production. Many of these are smaller reservoirs that standing
alone cannot justify the economics of a host production facility. As a result,
we expect that the Deepwater Gulf will be developed in a hub and satellite field
concept that resembles the approach the airline industry has used with regional
hub locations. We expect significant opportunities as this occurs. At the Marco
Polo field, our 50% ownership in the production facility will allow us to
realize a return on investment consisting of both a fixed monthly demand charge
and a volumetric tariff charge. In addition, we will assist with the
installation of the TLP and work to develop the surrounding acreage that can be
tied back to the platform by our construction vessels. Through our 20% interest
in the Gunnison field, we also own an interest in the spar production facility.

CUSTOMERS

Our customers include major and independent oil and gas producers, pipeline
transmission companies and offshore engineering and construction firms. The
level of construction services required by any particular customer depends on
the size of that customer's capital expenditure budget devoted to construction
plans in a particular year. Consequently, customers that account for a
significant portion of contract revenues in one fiscal year may represent an
immaterial portion of contract revenues in subsequent fiscal years. The percent
of consolidated revenue of major customers was as follows: 2003 -- Shell Trading
(US) Company (10%) and Petrocom Energy Group Ltd. (10%); 2002 -- Horizon
Offshore, Inc. (10%) and BP Trinidad & Tobago LLC (11%); 2001 -- Horizon
Offshore, Inc. (18%) and Enron Corp. (10%). Shell Trading, Petrocom and Enron
were purchasers of ERT's oil and gas production. Marine contracting revenues
from Horizon Offshore, Inc. were 5%, 10% and 18% of consolidated revenues during
the years ended December 31, 2003, 2002 and 2001, respectively. We estimate that
in 2003 we provided subsea services to over 200 customers. Our projects are
typically of short duration and are generally awarded shortly before
mobilization. Accordingly, we believe backlog is not a meaningful indicator of
future business results.

10

COMPETITION

The marine contracting industry is highly competitive. While price is a
factor, the ability to acquire specialized vessels, attract and retain skilled
personnel, and demonstrate a good safety record are also important. Our
competitors on the OCS include Global Industries Ltd., Oceaneering
International, Inc., Stolt Offshore S.A., Torch Offshore, Inc., and a number of
smaller companies, some of which only operate a single vessel and often compete
solely on price. For Deepwater projects, our principal competitors include Stolt
Offshore S.A., Subsea 7, Technip-Coflexip and Torch.

ERT encounters significant competition for the acquisition of mature oil
and gas properties. Our ability to acquire additional properties depends upon
our ability to evaluate and select suitable properties and consummate
transactions in a highly competitive environment. Competition includes TETRA
Technologies, Inc. and Superior Energy Services, Inc. Many potential purchasers
of oil and gas properties are well-established companies with substantially
larger operating staffs and greater capital resources.

TRAINING, SAFETY AND QUALITY ASSURANCE

We have established a corporate culture in which safety is expected to be
among the highest priorities. Our corporate goal, based on the belief that all
accidents are preventable, is to provide an injury-free workplace by focusing on
correct safety behavior. Our safety procedures and training programs were
developed by management personnel who came into the industry as divers and who
know first hand the physical challenges of the ocean work site. As a result,
management believes that our safety programs are among the best in the industry.
We have introduced a company-wide effort to enhance a behavioral safety process
and training program that makes safety a constant focus of awareness through
open communication with all offshore and yard employees. The process includes
the documentation of all daily observations and the collection of this data. In
addition, we initiated regular monthly visits by project managers to conduct
"Hazard Hunts" on each vessel, providing a "safety audit" with a fresh
perspective. Results from this program were evident as our safety performance
improved significantly in 2002 and 2003.

GOVERNMENT REGULATION

Many aspects of the offshore marine construction industry are subject to
extensive governmental regulations. We are subject to the jurisdiction of the
Coast Guard, the Environmental Protection Agency, the MMS and the U.S. Customs
Service, as well as private industry organizations such as the American Bureau
of Shipping. In the North Sea, regulations govern working hours and a specified
working environment, as well as standards for diving procedures, equipment and
diver health. These North Sea standards are some of the most stringent
worldwide. In the absence of any specific regulation, our North Sea branch
adheres to standards set by the International Marine Contractors Association and
the International Maritime Organisation.

We support and voluntarily comply with standards of the Association of
Diving Contractors International. The Coast Guard sets safety standards and is
authorized to investigate vessel and diving accidents, and to recommend improved
safety standards. The Coast Guard also is authorized to inspect vessels at will.
We are required by various governmental and quasi-governmental agencies to
obtain various permits, licenses and certificates with respect to our
operations. We believe that we have obtained or can obtain all permits, licenses
and certificates necessary for the conduct of our business.

In addition, we depend on the demand for our services from the oil and gas
industry and, therefore, our business is affected by laws and regulations, as
well as changing taxes and policies relating to the oil and gas industry
generally. In particular, the development and operation of oil and gas
properties located on the OCS of the United States is regulated primarily by the
MMS.

The MMS requires lessees of OCS properties to post bonds or provide other
adequate financial assurance in connection with the plugging and abandonment of
wells located offshore and the removal of all production facilities. Operators
on the OCS are currently required to post an area-wide bond of $3.0 million, or

11

$500,000 per producing lease. We have provided adequate financial assurance for
our offshore leases as required by the MMS.

We acquire production rights to offshore mature oil and gas properties
under federal oil and gas leases, which the MMS administers. These leases
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act, or
OCSLA. These MMS directives are subject to change. The MMS has promulgated
regulations requiring offshore production facilities located on the OCS to meet
stringent engineering and construction specifications. The MMS also has issued
regulations restricting the flaring or venting of natural gas and prohibiting
the burning of liquid hydrocarbons without prior authorization. Similarly, the
MMS has promulgated other regulations governing the plugging and abandonment of
wells located offshore and the removal of all production facilities. Finally,
under certain circumstances, the MMS may require any operations on federal
leases to be suspended or terminated or may expel unsafe operators from existing
OCS platforms and bar them from obtaining future leases. Suspension or
termination of our operations or expulsion from operating on our leases and
obtaining future leases could have a material adverse effect on our financial
condition and results of operations.

Under OCSLA and the Federal Oil and Gas Royalty Management Act, MMS also
administers oil and gas leases and establishes regulations that set the basis
for royalties on oil and gas produced from the leases. The MMS amends these
regulations from time to time. For example, on March 15, 2000, the MMS issued a
final rule governing the calculation of royalties and the valuation of crude oil
produced from federal leases (the "2000 Oil Rule"). The rule modified the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on oil posted prices and assign a value to
crude oil that better reflects market value. The rule has been challenged in the
United States District Court for the District of Columbia by two industry trade
associations, but that litigation is currently inactive, although a motion for
its reactivation has been filed by the state of California. As a result of the
litigation and MMS's experience with enforcing the 2000 Oil Rule, on August 20,
2003, MMS published a proposed rule which would amend provisions in the 2000 Oil
Rule regarding the valuation of non-arm's-length sales and the calculation of
transportation allowances. MMS is expected to finalize the rule early in
calendar year 2004.

Further, in 1997, the MMS issued a final rule amending its regulations
regarding costs for natural gas transportation that are deductible for royalty
valuation purposes when natural gas is sold off-lease. Among other matters, for
purposes of computing royalties owed, the rule disallows as deductions certain
costs, such as aggregator/marketer fees and transportation imbalance charges and
associated penalties. A United States District Court enjoined substantial
portions of this rule on March 28, 2000. The United States appealed the district
court decision. On February 8, 2002, the Court of Appeals for the District of
Columbia reversed the District Court in part and reinstated the greater portion
of the rule. The United States Supreme Court denied the trade associations'
petition for review on January 13, 2003. An MMS proposal to formally repeal the
portion of the rule that remains enjoined following the Court of Appeals'
decision and to address other matters is expected by mid-2004.

Historically, the transportation and sale for resale of natural gas in
interstate commerce has been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978, or NGPA, and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission, or FERC. In the past,
the federal government has regulated the prices at which oil and gas could be
sold. While sales by producers of natural gas, and all sales of crude oil,
condensate and natural gas liquids currently can be made at uncontrolled market
prices, Congress could reenact price controls in the future. Deregulation of
wellhead sales in the natural gas industry began with the enactment of the NGPA.
In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended
the NGPA to remove both price and non-price controls from natural gas sold in
"first sales" no later than January 1, 1993.

Sales of natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation remain
subject to extensive federal and state regulation. Several major regulatory
changes have been implemented by Congress and the FERC from 1985 to the present
that affect the economics of natural gas production, transportation and sales.
In addition, the FERC continues to promulgate revisions to various aspects of
the rules and regulations affecting those segments of the natural gas

12

industry, most notably interstate natural gas transmission companies that remain
subject to FERC jurisdiction. These initiatives may also affect the intrastate
transportation of natural gas under certain circumstances. The stated purpose of
many of these regulatory changes is to promote competition among the various
sectors of the natural gas industry. The ultimate impact of the complex rules
and regulations issued by the FERC since 1985 cannot be predicted.

We cannot predict what further action the FERC will take on these matters,
but we do not believe any such action will materially affect us differently than
other companies with which we compete.

Additional proposals and proceedings before various federal and state
regulatory agencies and the courts could affect the oil and gas industry. We
cannot predict when or whether any such proposals may become effective. In the
past, the natural gas industry has been heavily regulated. There is no assurance
that the regulatory approach currently pursued by the FERC will continue
indefinitely. Notwithstanding the foregoing, we do not anticipate that
compliance with existing federal, state and local laws, rules and regulations
will have a material effect upon our capital expenditures, earnings or
competitive position.

ENVIRONMENTAL REGULATION

Our operations are subject to a variety of national (including federal,
state and local) and international laws and regulations governing the discharge
of materials into the environment or otherwise relating to environmental
protection. Numerous governmental departments issue rules and regulations to
implement and enforce such laws that are often complex and costly to comply with
and that carry substantial administrative, civil and possibly criminal penalties
for failure to comply. Under these laws and regulations, we may be liable for
remediation or removal costs, damages and other costs associated with releases
of hazardous materials including oil into the environment, and such liability
may be imposed on us even if the acts that resulted in the releases were in
compliance with all applicable laws at the time such acts were performed. Some
of the environmental laws and regulations that are applicable to our business
operations are discussed in the following paragraphs, but the discussion does
not cover all environmental laws and regulations that govern our operations.

The Oil Pollution Act of 1990, as amended, or OPA, imposes a variety of
requirements on "responsible parties" related to the prevention of oil spills
and liability for damages resulting from such spills in waters of the United
States. A "Responsible Party" includes the owner or operator of an onshore
facility, a vessel or a pipeline, and the lessee or permittee of the area in
which an offshore facility is located. OPA imposes liability on each Responsible
Party for oil spill removal costs and for other public and private damages from
oil spills. Failure to comply with OPA may result in the assessment of civil and
criminal penalties. OPA establishes liability limits of $350 million for onshore
facilities, all removal costs plus $75 million for offshore facilities and the
greater of $500,000 or $600 per gross ton for vessels other than tank vessels.
The liability limits are not applicable, however, if the spill is caused by
gross negligence or willful misconduct; if the spill results from violation of a
federal safety, construction, or operating regulation; or if a party fails to
report a spill or fails to cooperate fully in the cleanup. Few defenses exist to
the liability imposed under OPA. Management is currently unaware of any oil
spills for which we have been designated as a Responsible Party under OPA that
will have a material adverse impact on us or our operations.

OPA also imposes ongoing requirements on a Responsible Party, including
preparation of an oil spill contingency plan and maintaining proof of financial
responsibility to cover a majority of the costs in a potential spill. We believe
we have appropriate spill contingency plans in place. With respect to financial
responsibility, OPA requires the Responsible Party for certain offshore
facilities to demonstrate financial responsibility of not less than $35 million,
with the financial responsibility requirement potentially increasing up to $150
million if the risk posed by the quantity or quality of oil that is explored for
or produced indicates that a greater amount is required. The MMS has promulgated
regulations implementing these financial responsibility requirements for covered
offshore facilities. Under the MMS regulations, the amount of financial
responsibility required for an offshore facility is increased above the minimum
amounts if the "worst case" oil spill volume calculated for the facility exceeds
certain limits established in the regulations. We believe that we currently have
established

13

adequate proof of financial responsibility for our onshore and offshore
facilities and that we satisfy the MMS requirements for financial responsibility
under OPA and applicable regulations.

OPA also requires owners and operators of vessels over 300 gross tons to
provide the Coast Guard with evidence of financial responsibility to cover the
cost of cleaning up oil spills from such vessels. We currently own and operate
six vessels over 300 gross tons. Satisfactory evidence of financial
responsibility has been provided to the Coast Guard for all of our vessels.

The Clean Water Act imposes strict controls on the discharge of pollutants
into the navigable waters of the U.S. and imposes potential liability for the
costs of remediating releases of petroleum and other substances. The controls
and restrictions imposed under the Clean Water Act have become more stringent
over time, and it is possible that additional restrictions will be imposed in
the future. Permits must be obtained to discharge pollutants into state and
federal waters. Certain state regulations and the general permits issued under
the Federal National Pollutant Discharge Elimination System program prohibit the
discharge of produced waters and sand, drilling fluids, drill cuttings and
certain other substances related to the exploration for and production of oil
and gas into certain coastal and offshore waters. The Clean Water Act provides
for civil, criminal and administrative penalties for any unauthorized discharge
of oil and other hazardous substances and imposes liability on responsible
parties for the costs of cleaning up any environmental contamination caused by
the release of a hazardous substance and for natural resource damages resulting
from the release. Many states have laws that are analogous to the Clean Water
Act and also require remediation of releases of petroleum and other hazardous
substances in state waters. Our vessels routinely transport diesel fuel to
offshore rigs and platforms and also carry diesel fuel for their own use. Our
vessels transport bulk chemical materials used in drilling activities and also
transport liquid mud which contains oil and oil by-products. Offshore facilities
and vessels operated by us have facility and vessel response plans to deal with
potential spills of oil or its derivatives. We believe that our operations
comply in all material respects with the requirements of the Clean Water Act and
state statutes enacted to control water pollution.

OCSLA provides the federal government with broad discretion in regulating
the production of offshore resources of oil and gas, including authority to
impose safety and environmental protection requirements applicable to lessees
and permittees operating in the OCS. Specific design and operational standards
may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations
of lease conditions or regulations issued pursuant to OCSLA can result in
substantial civil and criminal penalties, as well as potential court injunctions
curtailing operations and cancellation of leases. Because our operations rely on
offshore oil and gas exploration and production, if the government were to
exercise its authority under OCSLA to restrict the availability of offshore oil
and gas leases, such action could have a material adverse effect on our
financial condition and results of operations. As of this date, we believe we
are not the subject of any civil or criminal enforcement actions under OCSLA.

The Comprehensive Environmental Response, Compensation, and Liability Act,
or CERCLA, contains provisions requiring the remediation of releases of
hazardous substances into the environment and imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
including owners and operators of contaminated sites where the release occurred
and those companies who transport, dispose of or who arrange for disposal of
hazardous substances released at the sites. Under CERCLA, such persons may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages
to natural resources and for the costs of certain health studies. Third parties
may also file claims for personal injury and property damage allegedly caused by
the release of hazardous substances. Although we handle hazardous substances in
the ordinary course of business, we are not aware of any hazardous substance
contamination for which we may be liable.

We operate in foreign jurisdictions that have various types of governmental
laws and regulations relating to the discharge of oil or hazardous substances
and the protection of the environment. Pursuant to these laws and regulations,
we could be held liable for remediation of some types of pollution, including
the release of oil, hazardous substances and debris from production, refining or
industrial facilities, as well as other assets we own or operate or which are
owned or operated by either our customers or our sub-contractors.

14

Management believes that we are in compliance in all material respects with
all applicable environmental laws and regulations to which we are subject. We do
not anticipate that compliance with existing environmental laws and regulations
will have a material effect upon our capital expenditures, earnings or
competitive position. However, changes in the environmental laws and
regulations, or claims for damages to persons, property, natural resources or
the environment, could result in substantial costs and liabilities, and thus
there can be no assurance that we will not incur significant environmental
compliance costs in the future.

EMPLOYEES

We rely on the high quality of our workforce. As of December 31, 2003, we
had 1,114 employees, 258 of which were salaried. As of that date, we also
utilized approximately 500 non-U.S. citizens to crew our foreign flag vessels
under a crewing contract with C-MAR Services (UK), Ltd. of Aberdeen, Scotland.
None of our employees belong to a union or are employed pursuant to any
collective bargaining agreement or any similar arrangement. We believe that our
relationship with our employees and foreign crew members is good.

WEBSITE AND OTHER AVAILABLE INFORMATION

The Company maintains a website on the Internet with the address of
www.caldive.com. Copies of this Annual Report on Form 10-K for the year ended
December 31, 2003, and copies of the Company's Quarterly Reports on Form 10-Q
for 2003 and 2004 and any Current Reports on Form 8-K for 2003 and 2004, and any
amendments thereto, are or will be available free of charge at such website as
soon as reasonably practicable after they are filed with, or furnished to, the
SEC. Information contained on the Company's website is not part of this report.

The general public may read and copy any materials the Company files with
the SEC at the SEC's Public Reference Room at 450 Fifth Street, N.W.,
Washington, D.C. 20549. The public may obtain information on the operation of
the Public Reference Room by calling the SEC at 1-800-SEC-0330. The Company is
an electronic filer, and the SEC maintains an Internet website that contains
reports, proxy and information statements, and other information regarding
issuers that file electronically with the SEC, including the Company. The
Internet address of the SEC's website is www.sec.gov.

15

FACTORS INFLUENCING FUTURE RESULTS AND
ACCURACY OF FORWARD-LOOKING STATEMENTS

Shareholders should carefully consider the following risk factors in
addition to the other information contained herein. This Annual Report on Form
10-K includes certain statements that may be deemed "forward-looking statements"
within the meaning of Section 27A of the Securities Act and Section 21E of the
Exchange Act. You can identify these statements by forward-looking words such as
"anticipate," "believe," "budget," "could," "estimate," "expect," "forecast,"
"intend," "may," "plan," "potential," "should," "will" and "would' or similar
words. You should read statements that contain these words carefully because
they discuss our future expectations, contain projections of our future
financial position or results of operations or state other forward-looking
information. We believe that it is important to communicate our future
expectations to our investors. However, there may be events in the future that
we are not able to predict or control accurately. The factors listed below in
this section, captioned "Factors Influencing Future Results and Accuracy of
Forward-Looking Statements," as well as any cautionary language in this Annual
Report, provide examples of risks, uncertainties and events that may cause our
actual results to differ materially from the expectations we describe in our
forward-looking statements. You should be aware that the occurrence of the
events described in these risk factors and elsewhere in this Annual Report could
have a material adverse effect on our business, results of operations and
financial position.

OUR BUSINESS IS ADVERSELY AFFECTED BY LOW OIL AND GAS PRICES AND BY THE
CYCLICALITY OF THE OIL AND GAS INDUSTRY.

Our business is substantially dependent upon the condition of the oil and
gas industry and, in particular, the willingness of oil and gas companies to
make capital expenditures for offshore exploration, drilling and production
operations. The level of capital expenditures generally depends on the
prevailing view of future oil and gas prices, which are influenced by numerous
factors affecting the supply and demand for oil and gas, including, but not
limited to:

- Worldwide economic activity,

- Economic and political conditions in the Middle East and other
oil-producing regions,

- Coordination by the Organization of Petroleum Exporting Countries, or
OPEC,

- The cost of exploring for and producing oil and gas,

- The sale and expiration dates of offshore leases in the United States and
overseas,

- The discovery rate of new oil and gas reserves in offshore areas,

- Technological advances,

- Interest rates and the cost of capital,

- Environmental regulations, and

- Tax policies.

The level of offshore construction activity did not increase despite higher
commodity prices in 2003. We cannot assure you that activity levels will
increase anytime soon. A sustained period of low drilling and production
activity or the return of lower commodity prices would likely have a material
adverse effect on our financial position and results of operations.

THE OPERATION OF MARINE VESSELS IS RISKY, AND WE DO NOT HAVE INSURANCE COVERAGE
FOR ALL RISKS.

Marine construction involves a high degree of operational risk. Hazards,
such as vessels sinking, grounding, colliding and sustaining damage from severe
weather conditions, are inherent in marine operations. These hazards can cause
personal injury or loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.
Damage arising from such occurrences may result in lawsuits asserting large
claims. We maintain such insurance protection as we deem
16

prudent, including Jones Act employee coverage, which is the maritime equivalent
of workers' compensation, and hull insurance on our vessels. We cannot assure
you that any such insurance will be sufficient or effective under all
circumstances or against all hazards to which we may be subject. A successful
claim for which we are not fully insured could have a material adverse effect on
us. Moreover, we cannot assure you that we will be able to maintain adequate
insurance in the future at rates that we consider reasonable. As a result of
market conditions, premiums and deductibles for certain of our insurance
policies have increased substantially, and could escalate further. In some
instances, certain insurance could become unavailable or available only for
reduced amounts of coverage. For example, insurance carriers are now requiring
broad exclusions for losses due to war risk and terrorist acts. As construction
activity expands into deeper water in the Gulf, a greater percentage of our
revenues may be from Deepwater construction projects that are larger and more
complex, and thus riskier, than shallow water projects. As a result, our
revenues and profits are increasingly dependent on our larger vessels. The
current insurance on our vessels, in some cases, is in amounts approximating
book value, which is less than replacement value. In the event of property loss
due to a catastrophic marine disaster, mechanical failure or collision,
insurance may not cover a substantial loss of revenues, increased costs and
other liabilities, and could have a material adverse effect on our operating
performance if we were to lose any of our large vessels.

OUR CONTRACTING BUSINESS DECLINES IN WINTER, AND BAD WEATHER IN THE GULF OR
NORTH SEA CAN ADVERSELY AFFECT OUR OPERATIONS.

Marine operations conducted in the Gulf and North Sea are seasonal and
depend, in part, on weather conditions. Historically, we have enjoyed our
highest vessel utilization rates during the summer and fall when weather
conditions are favorable for offshore exploration, development and construction
activities. We typically have experienced our lowest utilization rates in the
first quarter. As is common in the industry, we typically bear the risk of
delays caused by some, but not all, adverse weather conditions. Accordingly, our
results in any one quarter are not necessarily indicative of annual results or
continuing trends.

IF WE BID TOO LOW ON A TURNKEY CONTRACT, WE SUFFER CONSEQUENCES.

A majority of our projects are performed on a qualified turnkey basis where
described work is delivered for a fixed price and extra work, which is subject
to customer approval, is billed separately. The revenue, cost and gross profit
realized on a turnkey contract can vary from the estimated amount because of
changes in offshore job conditions, variations in labor and equipment
productivity from the original estimates, and the performance of others such as
alliance partners. These variations and risks inherent in the marine
construction industry may result in our experiencing reduced profitability or
losses on projects.

ESTIMATES OF OUR OIL AND GAS RESERVES, FUTURE CASH FLOWS AND ABANDONMENT COSTS
MAY BE SIGNIFICANTLY INCORRECT.

Our proved reserves at December 31, 2003, included the reserves assigned to
our ownership position in the Gunnison project, a Deepwater Gulf of Mexico oil
and gas field operated by Kerr-McGee Oil & Gas Corp. These reserves constitute
nearly 50% of our total proved reserves as of December 31, 2003. This Annual
Report contains estimates of our proved oil and gas reserves and the estimated
future net cash flows therefrom based upon reports for the year ended December
31, 2003, audited by our independent petroleum engineers. These reports rely
upon various assumptions, including assumptions required by the Securities and
Exchange Commission, as to oil and gas prices, drilling and operating expenses,
capital expenditures, abandonment costs, taxes and availability of funds. The
process of estimating oil and gas reserves is complex, requiring significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. As a result,
these estimates are inherently imprecise. Actual future production, cash flows,
development expenditures, operating and abandonment expenses and quantities of
recoverable oil and gas reserves may vary substantially from those estimated in
these reports. Any significant variance in these assumptions could materially
affect the estimated quantity and value of our proved reserves. You should not
assume that the present value of future net cash flows from our proved reserves
referred to in this Annual Report is the current market value of our estimated
oil and gas reserves. In accordance with Securities and

17

Exchange Commission requirements, we base the estimated discounted future net
cash flows from our proved reserves on prices and costs on the date of the
estimate. Actual future prices and costs may differ materially from those used
in the net present value estimate. In addition, if costs of abandonment are
materially greater than our estimates, they could have an adverse effect on
earnings.

EXPECTED CASH FLOWS FROM THE Q4000, INTREPID AND SEAWELL, AS WELL AS CANYON, MAY
NOT BE IMMEDIATE OR AS HIGH AS EXPECTED.

The Q4000, Intrepid and the Seawell are vessels that were placed into
service during 2002. In addition, during 2002 we acquired Canyon Offshore, Inc.,
a supplier of ROVs to the offshore construction and telecommunications industry.
While we believe demand and market rates should improve, we will not receive any
material increase in revenue or cash flow from their operation until there is
significant improvements in demand and market rates. We cannot assure you that
customer demand for these vessels and Canyon's services will be as high as
currently anticipated and, as a result, our future cash flows may be adversely
affected. New vessels from third parties may also enter the market in the coming
years and compete with the Q4000, Intrepid and the Seawell for contracts.

OUR OIL AND GAS OPERATIONS INVOLVE SIGNIFICANT RISKS, AND WE DO NOT HAVE
INSURANCE COVERAGE FOR ALL RISKS.

Our oil and gas operations are subject to risks incident to the operation
of oil and gas wells, including, but not limited to, uncontrollable flows of
oil, gas, brine or well fluids into the environment, blowouts, cratering,
mechanical difficulties, fires, explosions, pollution and other risks, any of
which could result in substantial losses to us. We maintain insurance against
some, but not all, of the risks described above.

WE MAY NOT BE ABLE TO COMPETE SUCCESSFULLY AGAINST CURRENT AND FUTURE
COMPETITORS.

The business in which we operate is highly competitive. Several of our
competitors are substantially larger and have greater financial and other
resources than we have. If other companies relocate or acquire vessels for
operations in the Gulf or the North Sea, levels of competition may increase and
our business could be adversely affected.

THE LOSS OF THE SERVICES OF ONE OR MORE OF OUR KEY EMPLOYEES, OR OUR FAILURE TO
ATTRACT AND RETAIN OTHER HIGHLY QUALIFIED PERSONNEL IN THE FUTURE, COULD DISRUPT
OUR OPERATIONS AND ADVERSELY AFFECT OUR FINANCIAL RESULTS.

Our industry has lost a significant number of experienced subsea
professionals over the years due to, among other reasons, the volatility in
commodity prices. Our continued success depends on the active participation of
our key employees. The loss of our key people could adversely affect our
operations. We believe that our success and continued growth are also dependent
upon our ability to attract and retain skilled personnel. We believe that our
wage rates are competitive; however, unionization or a significant increase in
the wages paid by other employers could result in a reduction in our workforce,
increases in the wage rates we pay, or both. If either of these events occurs
for any significant period of time, our revenues and profitability could be
diminished and our growth potential could be impaired.

IF WE FAIL TO EFFECTIVELY MANAGE OUR GROWTH, OUR RESULTS OF OPERATIONS COULD BE
HARMED.

We have a history of growing through acquisitions of large assets and
acquisitions of companies. We must plan and manage our acquisitions effectively
to achieve revenue growth and maintain profitability in our evolving market. If
we fail to effectively manage current and future acquisitions, our results of
operations could be adversely affected. Our growth has placed, and is expected
to continue to place, significant demands on our personnel, management and other
resources. We must continue to improve our operational, financial, management
and legal/compliance information systems to keep pace with the growth of our
business.

18

WE MAY NEED TO CHANGE THE MANNER IN WHICH WE CONDUCT OUR BUSINESS IN RESPONSE TO
CHANGES IN GOVERNMENT REGULATIONS.

Our subsea construction, intervention, inspection, maintenance and
decommissioning operations and our oil and gas production from offshore
properties, including decommissioning of such properties, are subject to and
affected by various types of government regulation, including numerous federal,
state and local environmental protection laws and regulations. These laws and
regulations are becoming increasingly complex, stringent and expensive to comply
with, and significant fines and penalties may be imposed for noncompliance. We
cannot assure you that continued compliance with existing or future laws or
regulations will not adversely affect our operations.

CERTAIN PROVISIONS OF OUR CORPORATE DOCUMENTS AND MINNESOTA LAW MAY DISCOURAGE A
THIRD PARTY FROM MAKING A TAKEOVER PROPOSAL.

In addition to the 55,000 shares of preferred stock issued or issuable to
Fletcher International, Ltd. under the First Amended and Restated Agreement
dated January 17, 2003, but effective as of December 31, 2002, by and between
Cal Dive and Fletcher International, Ltd., our board of directors has the
authority, without any action by our shareholders, to fix the rights and
preferences on up to 4,945,000 shares of undesignated preferred stock, including
dividend, liquidation and voting rights. In addition, our by-laws divide the
board of directors into three classes. We are also subject to certain
anti-takeover provisions of the Minnesota Business Corporation Act. We also have
employment contracts with all of our senior officers that require cash payments
in the event of a "change of control." Any or all of the provisions or factors
described above may have the effect of discouraging a takeover proposal or
tender offer not approved by management and the board of directors and could
result in shareholders who may wish to participate in such a proposal or tender
offer receiving less for their shares than otherwise might be available in the
event of a takeover attempt.

ITEM 2. PROPERTIES

OUR VESSELS

We own a fleet of 21 vessels and 25 ROVs and trenchers. We also lease one
vessel. We believe that the Gulf market requires specially designed and/or
equipped vessels to competitively deliver subsea construction services. Nine of
our vessels have DP capabilities specifically designed to respond to the
Deepwater market requirements. Eight of our vessels (six of which are based in
the Gulf) have the capability to provide saturation diving services. Recent
developments in our fleet include:

Q4000: We began construction of our newest Ultra-Deepwater MSV, the Q4000
in 1999, and accepted her delivery in early 2002. The vessel cost approximately
$170 million and incorporates our latest semi-submersible technologies,
including various patented elements such as the absence of lower hull cross
bracing. A variable deck load of over 4,000 metric tons and upgraded well
completions capability make the vessel particularly well suited for large
offshore construction projects in the Ultra-Deepwater. Its Huisman-Itrec
multi-purpose tower has an open face which allows free access from three sides,
an advantage for a construction and intervention vessel.

Intrepid: The Intrepid offers customers a pipelay/construction vessel
capable of carrying an 8,000 metric ton deck load. She began work in June of
2002.

Eclipse: This large DP DSV is 370 feet long, 67 feet wide, and includes a
saturation diving system and DP-2. The Eclipse began work in March 2002.

Seawell: This purpose-build 364 foot mono-hull DP vessel, capable of
supporting both manned diving and ROVs, was recently upgraded for coiled tubing
deployment and well testing. The Seawell was purchased in July 2002.

ROVs: Canyon currently operates 20 ROVs and five trencher systems. In
2003, Canyon took delivery of three new Triton XLS ROV systems and a state of
the art "T750" Super Trencher.

19

LISTING OF VESSELS, BARGE AND ROVS

- ---------------

(1) Under government regulations and our insurance policies, we are required to
maintain our vessels in accordance with standards of seaworthiness and
safety set by government regulations and classification organizations. We
maintain our fleet to the standards for seaworthiness, safety and health set
by the American Bureau of Shipping, or ABS, Det Norske Veritas, or DNV, and
the U.S. Coast Guard, or USCG. The ABS is one of several classification
societies used by ship owners to certify that their vessels meet certain
structural, mechanical and safety equipment standards, including Lloyd's
Register, Bureau Veritas and DNV among others.

(2) Leased.

(3) Average age of ROV fleet is approximately 3.25 years.

We incur routine drydock inspection, maintenance and repair costs pursuant
to Coast Guard regulations and in order to maintain ABS or DNV classification
for our vessels. In addition to complying with these requirements, we have our
own vessel maintenance program that we believe permits us to continue to provide
our customers with well maintained, reliable vessels. In the normal course of
business, we charter other vessels

20

on a short-term basis, such as tugboats, cargo barges, utility boats and dive
support vessels. Most of our vessels are subject to ship mortgages to secure our
$70.0 million revolving credit facility, except the Northern Canyon (leased) and
the Q4000 (subject to liens to secure the MARAD financing guarantees).

SUMMARY OF NATURAL GAS AND OIL RESERVE DATA

The table below sets forth information, as of December 31, 2003, with
respect to estimates of net proved reserves and the present value of estimated
future net cash flows at such date, prepared in accordance with guidelines
established by the Securities and Exchange Commission. The Company's estimates
of reserves at December 31, 2003, have been audited by Huddleston & Co., Inc.,
independent petroleum engineers. All of the Company's reserves are located in
the United States. Proved reserves cannot be measured exactly because the
estimation of reserves involves numerous judgmental determinations. Accordingly,
reserve estimates must be continually revised as a result of new information
obtained from drilling and production history, new geological and geophysical
data and changes in economic conditions.

ITEM 3. LEGAL PROCEEDINGS

INSURANCE AND LITIGATION

Our operations are subject to the inherent risks of offshore marine
activity, including accidents resulting in personal injury and the loss of life
or property, environmental mishaps, mechanical failures, fires and collisions.
We insure against these risks at levels consistent with industry standards. We
also carry workers' compensation, maritime employer's liability, general
liability and other insurance customary in our business. All insurance is
carried at levels of coverage and deductibles that we consider financially
prudent. Our services are provided in hazardous environments where accidents
involving catastrophic damage or loss of life could occur, and litigation
arising from such an event may result in our being named a defendant in lawsuits
asserting large claims. To date, we have been involved in only one such claim,
where the cost of our vessel, the Balmoral Sea, was fully covered by insurance.
Although there can be no assurance that the amount of insurance we carry is
sufficient to protect us fully in all events, or that such insurance will
continue to be available at current levels of cost or coverage, we believe that
our insurance protection is adequate for our business operations. A successful
liability claim for which we are underinsured or uninsured could have a material
adverse effect on our business.

We are involved in various legal proceedings, primarily involving claims
for personal injury under the General Maritime Laws of the United States and the
Jones Act as a result of alleged negligence. In addition, we from time to time
incur other claims, such as contract disputes, in the normal course of business.
In that regard, in 1998, one of our subsidiaries entered into a subcontract with
Seacore Marine Contractors Limited ("Seacore") to provide a vessel to a Coflexip
subsidiary in Canada ("Coflexip"). Due to difficulties with respect to the sea
states and soil conditions the contract was terminated and an arbitration to
recover damages was commenced. A preliminary liability finding has been made by
the arbitrator against Seacore and in favor of the Coflexip subsidiary. We were
not a party to this arbitration proceeding. Seacore and Coflexip settled this

22

matter prior to the conclusion of the arbitration proceeding with Seacore paying
Coflexip $6.95 million CDN. Seacore has initiated an arbitration proceeding
against Cal Dive Offshore Ltd. ("CDO"), a subsidiary of Cal Dive, seeking
contribution of one-half of this amount. Because only one of the grounds in the
preliminary findings by the arbitrator is applicable to CDO, and because CDO
holds substantial counterclaims against Seacore, it is anticipated that our
subsidiary's exposure, if any, should be less than $500,000.

During 2002, we engaged in a large construction project and in late
September of that year, supports engineered by a subcontractor failed resulting
in over a month of downtime for two of CDI's vessels. Management believes that
under the terms of the contract, we are entitled to indemnification for the
contractual stand-by rate for the vessels during their downtime (the
indemnification claim). The customer has disputed these invoices along with
certain other change orders. Of the amounts billed by us for this project, $9.6
million had not been collected as of December 31, 2003. We have initiated
arbitration proceedings, in accordance with the terms of the contract, to
resolve this dispute.

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

None.

ITEM 5. EXECUTIVE OFFICERS OF THE COMPANY

The executive officers of Cal Dive are as follows:

Owen Kratz is Chairman and Chief Executive Officer of Cal Dive
International, Inc. He was appointed Chairman in May 1998 and has served as our
Chief Executive Officer since April 1997. Mr. Kratz served as President from
1993 until February 1999, and as a Director since 1990. He served as Chief
Operating Officer from 1990 through 1997. Mr. Kratz joined Cal Dive in 1984 and
has held various offshore positions, including saturation diving supervisor, and
has had management responsibility for client relations, marketing and
estimating. From 1982 to 1983, Mr. Kratz was the owner of an independent marine
construction company operating in the Bay of Campeche. Prior to 1982, he was a
superintendent for Santa Fe and various international diving companies, and a
saturation diver in the North Sea.

Martin R. Ferron has served on our Board of Directors since September 1998.
Mr. Ferron became President in February 1999 and has served as Chief Operating
Officer since January 1998. Mr. Ferron has 24 years of experience in the
oilfield industry, including seven in senior management positions with the
international operations of McDermott and Oceaneering. Mr. Ferron has a civil
engineering degree, a master's degree in marine technology, an MBA and is a
chartered civil engineer.

S. James Nelson, Jr. is Vice Chairman and has been a Director of Cal Dive
since 1990. Prior to October 2000, he was Executive Vice President and Chief
Financial Officer. From 1985 to 1988, Mr. Nelson was the Senior Vice President
and Chief Financial Officer of Diversified Energies, Inc., the former parent of
Cal Dive, at which time he had corporate responsibility for Cal Dive. From 1980
to 1985, Mr. Nelson served as Chief Financial Officer of Apache Corporation, an
oil and gas exploration and production company. From 1966 to 1980, Mr. Nelson
was employed with Arthur Andersen & Co., and, from 1976 to 1980, he was a
partner
23

serving on the firm's worldwide oil and gas industry team. Mr. Nelson received
an undergraduate degree (BS) from Holy Cross College and an MBA from Harvard
University; he is also a Certified Public Accountant.

James Lewis Connor, III became Senior Vice President and General Counsel of
Cal Dive in May 2002 and Corporate Secretary in July 2002. He had previously
served as Deputy General Counsel since May 2000. Mr. Connor has been involved
with the oil and gas industry for nearly 20 years, including 11 years in his
capacity as legal counsel to both companies and individuals. Prior to joining
Cal Dive, Mr. Connor was a Senior Counsel at El Paso Production Company
(formerly Sonat Exploration Company) from 1997 to 2000 and previously from 1995
to 1997 was a senior associate in the oil, gas and energy law section of
Hutcheson & Grundy, L.L.P. Mr. Connor received his Bachelor of Science degree
from Texas A&M University in 1979 and his law degree, with honors, from the
University of Houston in 1991.

A. Wade Pursell is Senior Vice President and Chief Financial Officer of Cal
Dive International, Inc. In this capacity, which he was appointed to in October
2000, Mr. Pursell oversees the finance, treasury, accounting, tax,
administration and corporate planning functions. He joined Cal Dive in May 1997,
as Vice President -- Finance and Chief Accounting Officer. From 1988 through
1997 he was with Arthur Andersen LLP, lastly as an Experienced Manager
specializing in the offshore services industry (which included servicing the Cal
Dive account from 1990 to 1997). Mr. Pursell received an undergraduate degree
(BS) from the University of Central Arkansas and is a Certified Public
Accountant.

Lloyd A. Hajdik joined the Company in December 2003 as Vice
President -- Corporate Controller. From January 2002 to November 2003 he was
Assistant Corporate Controller for Houston-based NL Industries, Inc. Prior to
NL, Mr. Hajdik served as Senior Manager of SEC Reporting and Accounting Services
for Compaq Computer Corporation from 2000 to 2002, and as Controller for
Halliburton's Baroid Drilling Fluids and Zonal Isolation product service lines
from 1997 to 2000. Mr. Hajdik served as Controller for Engineering Services for
Cliffs Drilling Company from 1995 to 1997 and was with Ernst & Young in the
audit practice from 1989 to 1995. Mr. Hajdik graduated from Southwest Texas
State University receiving a Bachelor of Business Administration degree. Mr.
Hajdik is a Certified Public Accountant and a member of the Texas Society of
CPAs as well as the American Institute of Certified Public Accountants.

ITEM 6. THE MANAGERS OF THE SUBSIDIARIES OF THE COMPANY

The Managers of the Subsidiaries of Cal Dive are as follows:

John Edwards became Co-President and Chief Operating Officer of Canyon
Offshore Inc. in January 2002 upon its merger with Cal Dive International, Inc.
Mr. Edwards co-founded Canyon in 1996 and initially served as Co-Chief Executive
Officer and Chief Operating Officer. Mr. Edwards has been involved in the subsea
industry for twenty-one years, with primary roles in commercial and marketing.
He was with Sonsub International from 1988 to 1996, beginning as Regional
Manager of South East Asia operations, and taking on later roles as
International Marketing Manager and Senior Vice President Commercial. Previously
he was with Oceonics PLC from 1982 to 1988.

Johnny Edwards has been President of ERT since March 2000. He joined ERT in
1994 as Engineering and Acquisitions Manager, where he has been instrumental in
the growth of the company. Prior to joining ERT, Mr. Edwards worked for ARCO Oil
& Gas Company for 19 years and held various technical and management positions
in engineering and operations. Mr. Edwards received a Bachelor of Science degree
in Chemical Engineering from Louisiana Tech University in 1975.

24

William F. Morrice became General Manager of Well Ops (U.K.) Limited, a
wholly owned subsidiary of Cal Dive International Inc., since the company was
formed in July 2002 and acquired the well intervention vessel MSV Seawell and
the Well Operations Business Unit of Technip-Coflexip. Mr. Morrice had
previously been with Technip-Coflexip for 13 years, having joined them as a
Project Engineer in 1990. Mr. Morrice assumed responsibility for the Well
Operations Business Unit that operates from the Seawell in 1995. Mr. Morrice
graduated from Robert Gordon's University in 1996 with a Bachelor of Science
degree and Postgraduate Diploma in Offshore Engineering. Further postgraduate
studies attained a Postgraduate Certificate in Project Management from Aberdeen
University.

Martin O'Carroll became Co-President and Chief Financial Officer of Canyon
Offshore Inc. in January 2002 upon its merger with Cal Dive International, Inc.
Mr. O'Carroll co-founded Canyon in 1996 and initially served as Co-Chief
Executive Officer and Chief Financial Officer. Mr. O'Carroll has been involved
in the subsea industry for fifteen years, with primary roles in finance and
administration. He was with Sonsub International from 1988 to 1996, serving as
Chief Financial Officer and later Senior Vice President of Finance and
Administration. Previously he was Manager of Price Waterhouse in Ireland and
Australia from 1980 to 1988. Mr. O'Carroll received his Bachelor of Commerce
degree in 1980 from the National University of Ireland, and is an Associate of
the Institute of Chartered Accountants in Ireland and Australia.

Ian Collie became General Manager of Well Ops Inc. a subsidiary of Cal Dive
International, Inc. of Houston in 2002, and had previously served as Well
Intervention Manager since 1999. Mr. Collie has been involved with the oil and
gas industry for 32 years which includes 28 years of offshore experience to
different companies. Prior to joining Cal Dive, Mr. Collie was a Well Operations
Superintendent at Coflexip Stena Offshore Ltd. (U.K. and U.S.A.) from 1990 to
1999.

25

PART II

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

Our common stock is traded on the Nasdaq National Market under the symbol
"CDIS." The following table sets forth, for the periods indicated, the high and
low closing sale prices per share of our common stock:

On March 10, 2004, the closing sale price of our common stock on the Nasdaq
National Market was $25.70 per share. As of March 10, 2004, there were an
estimated 4,170 beneficial holders of our common stock.

We have never declared or paid cash dividends on our common stock and do
not intend to pay cash dividends in the foreseeable future. We currently intend
to retain earnings, if any, for the future operation and growth of our business.
In addition, our financing arrangements prohibit the payment of cash dividends
on our common stock. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."

26

ITEM 6. SELECTED FINANCIAL DATA

The financial data presented below for each of the five years ended
December 31, 2003, should be read in conjunction with Management's Discussion
and Analysis of Financial Condition and Results of Operations and the
Consolidated Financial Statements and Notes to Consolidated Financial Statements
included elsewhere in this Form 10-K (in thousands, except per share amounts).

27

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

BUSINESS OVERVIEW

Oil and gas prices, the offshore mobile rig count, and Deepwater
construction activity are three of the primary indicators we use to forecast the
future performance of our Marine Contracting business. Our construction services
generally follow successful drilling activities by six to eighteen months on the
OCS and twelve months or longer in the Deepwater arena. The level of drilling
activity is related to both short- and long-term trends in oil and gas prices.
While oil and natural gas prices have been at robust levels for the last two
years, offshore drilling activity has yet to respond. Our primary leading
indicator, the number of offshore mobile rigs contracted, is currently at
approximately 115 rigs employed in the Gulf of Mexico, flat with year ago levels
and compared to 182 during the first quarter of 2001. The Deepwater Gulf is
principally being developed for oil, with the complexity of developing these
reservoirs resulting in significant lead times to first production.

Our business is substantially dependent upon the condition of the oil and
gas industry and, in particular, the willingness of oil and gas companies to
make capital expenditures for offshore exploration, drilling and production
operations. The level of capital expenditures generally depends on the
prevailing view of future oil and gas prices, which are influenced by numerous
factors affecting the supply and demand for oil and gas, including, but not
limited to:

- Worldwide economic activity,

- Economic and political conditions in the Middle East and other
oil-producing regions,

- Coordination by the Organization of Petroleum Exporting Countries, or
OPEC,

- The cost of exploring for and producing oil and gas,

- The sale and expiration dates of offshore leases in the United States and
overseas,

- The discovery rate of new oil and gas reserves in offshore areas,

- Technological advances,

- Interest rates and the cost of capital,

- Environmental regulations, and

- Tax policies.

The level of offshore construction activity did not increase despite higher
commodity prices in 2003. We cannot assure you that activity levels will
increase anytime soon. A sustained period of low drilling and production
activity or the return of lower commodity prices would likely have a material
adverse effect on our financial position and results of operations.

Product prices impact our oil and gas operations in several respects. We
seek to acquire producing oil and gas properties that are generally in the later
stages of their economic life. The sellers' potential abandonment liabilities
are a significant consideration with respect to the offshore properties we have
purchased to date. Although higher natural gas prices tend to reduce the number
of mature properties available for sale, these higher prices typically
contribute to improved operating results for ERT. In contrast, lower natural gas
prices typically contribute to lower operating results for ERT and a general
increase in the number of mature properties available for sale. We expanded the
scope of our gas and oil operations by taking a working interest in Gunnison, a
Deepwater Gulf development of Kerr-McGee Oil & Gas Corp., and participating in
the ownership of the Marco Polo production facility.

Our proved reserves at December 31, 2003, included the reserves assigned to
our ownership position in Gunnison. These reserves constitute nearly 50% of our
total proved reserves as of December 31, 2003. This Annual Report contains
estimates of our proved oil and gas reserves based upon reports audited by our
independent petroleum engineers. The process of estimating oil and gas reserves
is complex, requiring significant decisions and assumptions in the evaluation of
available geological, geophysical, engineering and
28

economic data for each reservoir. As a result, these estimates are inherently
imprecise. Actual future production, cash flows, development expenditures,
operating and abandonment expenses and quantities of recoverable oil and gas
reserves may vary substantially from those estimated in these reports. Any
significant variance in these assumptions could materially affect the estimated
quantity and value of our proved reserves.

Regarding marine contracting, vessel utilization is historically lower
during the first quarter due to winter weather conditions in the Gulf and the
North Sea. Accordingly, we plan our drydock inspections and other routine and
preventive maintenance programs during this period. During the first quarter, a
substantial number of our customers finalize capital budgets and solicit bids
for construction projects. The bid and award process during the first two
quarters typically leads to the commencement of construction activities during
the second and third quarters. As a result, we have historically generated up to
65% of our marine contracting revenues in the last six months of the year. Our
operations can also be severely impacted by weather during the fourth quarter.
Operation of oil and gas properties and production facilities tends to offset
the impact of weather since the first and fourth quarters are typically periods
of high demand and strong prices for natural gas. Due to this seasonality, full
year results are not likely to be a direct multiple of any particular quarter or
combination of quarters.

The following table sets forth for the periods presented average U.S.
natural gas prices, our equivalent natural gas production, the average number of
offshore rigs under contract in the Gulf, the number of platforms installed and
removed in the Gulf and the vessel utilization rates for each of the major
categories of our fleet.

- ---------------

(1) Henry Hub Gas Daily Average (the midpoint index price per Mmbtu for
deliveries into a specific pipeline for the applicable calendar day as
reported by Platts Gas Daily in the "Daily Price Survey" table).

(2) Average monthly number of rigs contracted, as reported by Offshore Data
Services.

(3) Source: Minerals Management Service (2003) and Offshore Data Services (2002
and 2001); installation and removal of platforms with two or more piles in
the Gulf.

(4) Average vessel utilization rate is calculated by dividing the total number
of days the vessels in this category generated revenues by the total number
of days in each quarter.

CRITICAL ACCOUNTING POLICIES

Our results of operations and financial condition, as reflected in the
accompanying financial statements and related footnotes, are subject to
management's evaluation and interpretation of business conditions, changing
capital market conditions and other factors which could affect the ongoing
viability of our business segments and/or our customers. We believe the most
critical accounting policies in this regard are the recognition of revenue and
the associated estimation of revenue allowance on gross amounts billed,
evaluation of recoverability of property and equipment and goodwill balances and
the accounting for decommissioning

29

liabilities for ERT. While these issues require us to make judgments that are
somewhat subjective, they are generally based on a significant amount of
historical data and current market data.

ERT acquisitions of producing offshore properties are recorded at the fair
value exchanged at closing together with an estimate of its proportionate share
of the decommissioning liability assumed in the purchase based upon its working
interest ownership percentage. In estimating the decommissioning liability
assumed in offshore property acquisitions, we perform detailed estimating
procedures, including engineering studies and then reflect the liability at fair
value on a discounted basis as discussed below. We follow the successful efforts
method of accounting for our interests in oil and gas properties. Under the
successful efforts method, the costs of successful wells and leases containing
productive reserves are capitalized. Costs incurred to drill and equip
development wells, including unsuccessful development wells, are capitalized.

The Company also considers the following accounting policies to be the most
critical to the preparation of its financial statements:

GOODWILL

The Company tests for the impairment of goodwill on at least an annual
basis. The Company's goodwill impairment test involves a comparison of the fair
value of each of the Company's reporting units. with its carrying amount. The
fair value is determined using discounted cash flows and other market-related
valuation models, such as earnings multiples and comparable asset market values.
These tests are influenced significantly by management estimates of future cash
flows and the related expected utilization of assets. Prior to the adoption of
Statement of Financial Accounting Standards ("SFAS") No. 142, Goodwill and
Indefinite-Lived Intangibles ("SFAS No. 142"), goodwill was amortized on a
straight line basis over 25 years. In conjunction with the adoption of this
statement, the Company has discontinued the amortization of goodwill.

PROPERTY AND EQUIPMENT

Property and equipment, both owned and under capital leases, are recorded
at cost. Depreciation is provided primarily on the straight-line method over the
estimated useful lives of the assets described in footnote 2 to the Consolidated
Financial Statements included herein.

For long-lived assets to be held and used, excluding goodwill, the Company
bases its evaluation on impairment indicators such as the nature of the assets,
the future economic benefit of the assets, any historical or future
profitability measurements and other external market conditions or factors that
may be present. If such impairment indicators are present or other factors exist
that indicate that the carrying amount of the asset may not be recoverable, the
Company determines whether an impairment has occurred through the use of an
undiscounted cash flows analysis of the asset at the lowest level for which
identifiable cash flows exist. If an impairment has occurred, the Company
recognizes a loss for the difference between the carrying amount and the fair
value of the asset. The fair value of the asset is measured using quoted market
prices or, in the absence of quoted market prices, is based on management's
estimate of discounted cash flows. Assets are classified as held for sale when
the Company has a plan for disposal of certain assets and those assets meet the
held for sale criteria.

The Company evaluates the impairment of its oil and gas properties on a
field-by-field basis whenever events or changes in circumstances indicate, but
at least annually, an asset's carrying amount may not be recoverable.
Unamortized capital costs are reduced to fair value if the expected undiscounted
future cash flows are less than the asset's net book value. Cash flows are
determined based upon proved reserves using prices and costs consistent with
those used for internal decision making. Although prices used are likely to
approximate market, they do not necessarily represent current market prices.
Given that spot market prices are subject to volatile changes, it is the
Company's opinion that a long-term view of market prices will lead to a more
appropriate valuation of long-term assets.

30

ACCOUNTING FOR DECOMMISSIONING LIABILITIES

SFAS No. 143, Accounting for Asset Retirement Obligations, addresses the
financial accounting and reporting obligations and retirement costs related to
the retirement of tangible long-lived assets. Among other things, SFAS No. 143
requires oil and gas companies to reflect decommissioning liabilities on the
face of the balance sheet at fair value on a discounted basis. ERT historically
has purchased producing offshore oil and gas properties that are in the later
stages of production. In conjunction with acquiring these properties, ERT
assumes an obligation associated with decommissioning the property in accordance
with the regulations set by government agencies. The abandonment liability
related to the acquisitions of these properties is determined through a series
of management estimates.

Prior to an acquisition and as part of evaluating the economics of an
acquisition, ERT will estimate the plug and abandonment liability. ERT personnel
prepare detailed cost estimates to plug and abandon wells and remove necessary
equipment in accordance with regulatory guidelines. ERT currently calculates the
discounted value of the abandonment liability (based on the estimated year the
abandonment will occur) in accordance with SFAS No. 143 and capitalizes that
portion as part of the basis acquired and records the related abandonment
liability at fair value.

On an ongoing basis, ERT personnel monitor the status of wells on the
properties and as fields deplete and no longer produce ERT will monitor the
timing requirements set forth by the MMS for plugging and abandoning the wells
and commence abandonment operations, when applicable. On an annual basis, ERT
and Cal Dive management personnel review and update the abandonment estimates
and assumptions, for changes, among other things, in market conditions, interest
rates and historical experience.

The adoption of SFAS No. 143 resulted in a cumulative effect adjustment as
of January 1, 2003 to record (i) a $33.1 million decrease in the carrying values
of proved properties, (ii) a $7.4 million decrease in accumulated depreciation,
depletion and amortization of property and equipment, (iii) a $26.5 million
decrease in decommissioning liabilities and (iv) a $0.3 million increase in
deferred income tax liabilities. The net impact of items (i) through (iv) was to
record a gain of $0.5 million, net of tax, as a cumulative effect adjustment of
a change in accounting principle in the Company's consolidated statements of
operations upon adoption on January 1, 2003. The Company has no material assets
that are legally restricted for purposes of settling its decommissioning
liabilities.

ACCOUNTING FOR REDEEMABLE STOCK IN SUBSIDIARY

SFAS No. 150, Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity, requires that certain financial
instruments, which under previous guidance were accounted for as equity, must
now be accounted for as liabilities. The financial instruments affected include
mandatorily redeemable stock, certain financial instruments that require or may
require the issuer to buy back some of its shares in exchange for cash or other
assets and certain obligations that can be settled with shares of stock. SFAS
No. 150 was effective for all financial instruments entered into or modified
after May 31, 2003. As a result of this adoption, the Company reclassified the
$4.9 million of Redeemable Stock in Subsidiary from mezzanine classification
(i.e., between liabilities and shareholders' equity on the balance sheet) to
debt. Otherwise, the adoption had no impact on the Company's consolidated
financial statements.

REVENUE RECOGNITION

The Company earns the majority of marine contracting revenues during the
summer and fall months. Revenues are derived from billings under contracts
(which are typically of short duration) that provide for either lump-sum turnkey
charges or specific time, material and equipment charges which are billed in
accordance with the terms of such contracts. The Company recognizes revenue as
it is earned at estimated collectible amounts. Revenues generated from specific
time, materials and equipment charges contracts are generally earned over a
dayrate basis and recognized as amounts are earned in accordance with contract
terms. Revenues generated in the pre-operation mode before a contract commences
are deferred and recognized in accordance with contract terms. Direct and
incremental costs associated with pre-operation activities are similarly
deferred and recognized over the estimated contract period.
31

Revenue on significant turnkey contracts is recognized on the
percentage-of-completion method based on the ratio of costs incurred to total
estimated costs at completion, or achievement of certain contractual milestones
if provided for in the contract. Contract price and cost estimates are reviewed
periodically as work progresses and adjustments are reflected in the period in
which such estimates are revised. Provisions for estimated losses on such
contracts are made in the period such losses are determined. Unbilled revenue
represents revenue attributable to work completed prior to year-end which has
not yet been invoiced. All amounts included in unbilled revenue at December 31,
2003 are expected to be billed and collected within one year.

The Company records revenues from the sales of crude oil and natural gas
when delivery to the customer has occurred and title has transferred. This
occurs when production has been delivered to a pipeline or a barge lifting has
occurred. The Company may have an interest with other producers in certain
properties. In this case the Company uses the entitlements method to account for
sales of production. Under the entitlements method the Company may receive more
or less than its entitled share of production. If the Company receives more than
its entitled share of production, the imbalance is treated as a liability. If
the Company receives less than its entitled share, the imbalance is recorded as
an asset.

REVENUE ALLOWANCE ON GROSS AMOUNTS BILLED

The Company bills for work performed in accordance with the terms of the
applicable contract. The gross amount of revenue billed will include not only
the billing for the original amount quoted for a project but also include
billings for services provided which the Company believes are allowed under the
terms of the related contract but are outside the scope of the original quote.
The Company establishes a revenue allowance for these additional billings based
on its collections history if conditions warrant such a reserve.

FOREIGN CURRENCY

The functional currency for the Company's foreign subsidiary, Well Ops
(U.K.) Limited, is the applicable local currency (British Pound). Results of
operations for this subsidiary are translated into U.S. dollars using average
exchange rates during the period. Assets and liabilities of this foreign
subsidiary are translated into U.S. dollars using the exchange rate in effect at
the balance sheet date and the resulting translation adjustment, which was a
gain of $5.0 million, net of taxes, and $2.5 million, net of taxes, in 2003 and
2002, respectively, is included as accumulated other comprehensive income, as a
component of shareholders' equity. All foreign currency transaction gains and
losses are recognized currently in the statements of operations.

Canyon Offshore, the Company's ROV subsidiary, has operations in the United
Kingdom and Southeast Asia sectors. Canyon conducts the majority of its affairs
in these regions in U.S. dollars which it considers the functional currency.
When currencies other than the U.S. dollar are to be paid or received the
resulting gain or loss from translation is recognized in the statements of
operations. These amounts for the years ended December 31, 2003 and 2002,
respectively, were not material to the Company's results of operations or cash
flows.

ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES

The Company's price risk management activities involve the use of
derivative financial instruments to hedge the impact of market price risk
exposures primarily related to our oil and gas production. All derivatives are
reflected in our balance sheet at their fair market value.

There are two types of hedging activities: hedges of cash flow exposure and
hedges of fair value exposure. The Company engages primarily in cash flow
hedges. Hedges of cash flow exposure are entered into to hedge a forecasted
transaction or the variability of cash flows to be received or paid related to a
recognized asset or liability. Changes in the derivative fair values that are
designated as cash flow hedges are deferred to the extent that they are
effective and are recorded as a component of accumulated other comprehensive
income until the hedged transactions occur and are recognized in earnings. The
ineffective portion of a cash flow hedge's change in value is recognized
immediately in earnings in oil and gas production revenues.
32

We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives, strategies for
undertaking various hedge transactions and our methods for assessing and testing
correlation and hedge ineffectiveness. All hedging instruments are linked to the
hedged asset, liability, firm commitment or forecasted transaction. We also
assess, both at the inception of the hedge and on an on-going basis, whether the
derivatives that are used in our hedging transactions are highly effective in
offsetting changes in cash flows of the hedged items. We discontinue hedge
accounting prospectively if we determine that a derivative is no longer highly
effective as a hedge or it is probable that a hedged transaction will not occur.
If hedge accounting is discontinued, deferred gains or losses on the hedging
instruments are recognized in earnings immediately.

The market value of hedging instruments reflects our best estimate and is
based upon exchange or over-the-counter quotations whenever they are available.
Quoted valuations may not be available due to location differences or terms that
extend beyond the period for which quotations are available. Where quotes are
not available, we utilize other valuation techniques or models to estimate
market values. These modeling techniques require us to make estimations of
future prices, price correlation and market volatility and liquidity. Our actual
results may differ from our estimates, and these differences can be positive or
negative.

During 2003 and 2002 the Company entered into various cash flow hedging
swap and costless collar contracts to fix cash flows relating to a portion of
the Company's oil and gas production. All of these qualified for hedge
accounting and none extended beyond a year and a half. The aggregate fair market
value of the swaps and collars was a liability of $2.2 million and $4.1 million
as of December 31, 2003 and 2002, respectively. For the years ended December 31,
2003 and 2002, the Company recorded a net of tax $1.2 million gain, and $2.6
million loss, respectively, in other comprehensive income (loss) within
shareholders' equity as these hedges were highly effective. The balance in the
fair value hedge adjustments account is recognized in earnings when the hedged
item is sold.

INCOME TAXES

Deferred income taxes are based on the difference between financial
reporting and tax bases of assets and liabilities. The Company utilizes the
liability method of computing deferred income taxes. The liability method is
based on the amount of current and future taxes payable using tax rates and laws
in effect at the balance sheet date. Income taxes have been provided based upon
the tax laws and rates in the countries in which operations are conducted and
income is earned. A valuation allowance for deferred tax assets is recorded when
it is more likely than not that some or all of the benefit from the deferred tax
asset will not be realized. See footnote 9 to the Consolidated Financial
Statements included herein for discussion of net operating loss carry forwards
and deferred income taxes.

WORKER'S COMPENSATION CLAIMS

Our onshore employees are covered by Worker's Compensation. Offshore
employees, including divers and tenders and marine crews, are covered by
Maritime Employers Liability insurance policy which covers Jones Act exposures.
The Company incurs worker's compensation claims in the normal course of
business, which management believes are covered by insurance. The Company, its
insurers and legal counsel analyze each claim for potential exposure and
estimate the ultimate liability of each claim.

ACCOUNTING PRINCIPLES NOT YET ADOPTED

In January 2003, FASB Interpretation ("FIN") No. 46, Consolidation of
Variable Interest Entities, was issued which requires companies that control
another entity through interests other than voting interests to consolidate the
controlled entity. FIN No. 46 applies immediately to variable interest entities
created after January 31, 2003, and applies in the first interim period
beginning after March 15, 2004 to variable interest entities created before
February 1, 2003. The related disclosure requirements are effective immediately.
The Company currently believes that it has no involvement with any variable
interest entity covered by the scope of FIN No. 46.

33

OTHER MATTERS

The FASB's Emerging Issues Task Force ("EITF") currently is deliberating on
EITF No. 03-O, Whether Mineral Rights Are Tangible or Intangible Assets, and
EITF No. 03-S, Application of FASB Statement No. 142, Goodwill and Other
Intangible Assets, to Oil and Gas Companies. These proposed statements will
determine whether contract-based oil and gas mineral rights are classified as
tangible or intangible assets based on the EITF's interpretation of SFAS No.
141, Business Combinations, and SFAS No. 142. Historically, the Company has
classified all of its contract-based mineral rights within property, plant and
equipment and has generally not identified these amounts separately. If the EITF
determines that these mineral rights should be presented as intangible assets,
the Company would have to reclassify its contract-based oil and gas mineral
rights acquired after June 30, 2001 to intangible assets and make additional
disclosures in accordance with SFAS No. 142. If The Company adopted this change,
approximately $51 million and $87 million of the property, plant and equipment
balance (net of accumulated depreciation, depletion and amortization) related to
proved properties would be reclassified to intangible assets at December 31,
2003 and 2002, respectively. The Company has been amortizing these amounts under
the unit-of-production method and would continue to amortize the mineral rights
under this method. Based on its understanding of the scope of the EITF
deliberations, the Company believes the adoption of this potential decision
would have no material effect on its results of operations.

RESULTS OF OPERATIONS

We derive our revenues, earnings and cash flows from two primary business
segments: Marine Contracting and Oil and Gas Production. Within Marine
Contracting, we operate primarily in the Gulf of Mexico (Gulf), and recently in
the North Sea and Asia/Pacific, with services that cover the lifecycle of an
offshore oil or gas field. Our current diversified fleet of 22 vessels and 25
remotely operated vehicles (ROVs) and trencher systems perform services that
support drilling, well completion, intervention, construction and
decommissioning projects involving pipelines, production platforms, risers and
subsea production systems. We also have a significant investment in offshore oil
and gas production as well as production facilities. Operations in the
Production Facilities segment should begin in 2004 as Marco Polo comes online.
Our customers include major and independent oil and gas producers, pipeline
transmission companies and offshore engineering and construction firms.

COMPARISON OF YEARS ENDED 2003 AND 2002

Revenues. During the year ended December 31, 2003, revenues increased
$93.6 million, or 31%, to $396.3 million compared to $302.7 million for the year
ended December 31, 2002. The Marine Contracting segment contributed $19.1
million of the increase, primarily as a result of the acquisition of the Seawell
during the third quarter of 2002. In addition, the Q4000, Intrepid and Eclipse
worked a full year in 2003 as compared to nine months in the prior year, as
these vessels were placed in service in the second quarter of 2002.

Oil and Gas Production revenue for the year ended December 31, 2003
increased $74.5 million, or 119%, to $137.3 million from $62.8 million during
the prior year. The increase was due to a 33% increase in our average realized
commodity prices to $4.82 per Mcfe, net of hedges in place ($4.98 per Mcfe of
natural gas and $27.63 per barrel of oil) in 2003 from $3.63 per Mcfe ($3.49 per
Mcfe of natural gas and $24.73 per barrel of oil) in 2002. Production increased
69% to 28 Bcfe during 2003 from 16.6 Bcfe during the prior year as a result of
the property acquisitions during the third quarter of 2002 and Gunnison coming
on line in December 2003.

Gross Profit. Gross profit of $92.1 million for 2003 was $38.3 million, or
71%, greater than the $53.8 million gross profit recorded in the prior year due
entirely to the revenue increase in Oil and Gas Production mentioned above. Oil
and Gas Production gross profit increased $39.4 million from $26.7 million in
2002 to $66.1 million for 2003, due to the increases in average realized
commodity prices and production described above.

Gross margins improved to 23% for the year ended December 31, 2003 compared
to 18% during 2002 due primarily to the aforementioned increases in average
realized commodity prices. Marine Contracting margins
34

decreased from 11% for 2002 to 10% during 2003 due mainly to the depressed
markets for offshore construction in the GOM and the North Sea, increased
competition in the OCS market and increased offshore insurance costs offset by
the impact of charges recorded in the fourth quarter of 2002 related to a
contract dispute.

Selling & Administrative Expenses. Selling and administrative expenses
were $35.9 million in 2003, which is 10% more than the $32.8 million incurred in
2002, primarily due to the addition of business units acquired and higher ERT
incentive accruals. Selling and administrative expenses were 9% of revenues for
2003, which was two points better than the 11% for 2002 due primarily to the EEX
settlement charges in the fourth quarter of 2002.

Other (Income) Expense. The Company reported other expense of $3.5 million
for the year ended December 31, 2003 in contrast to $2.0 million for 2002.
Included in other expense for 2002 is a $1.1 million gain on our foreign
currency derivative associated with the acquisition of Well Ops (U.K.) Limited
recorded in other income in June 2002. Net interest expense of $2.4 million for
2003 is higher than the $2.2 million in the prior year as a result of our higher
debt levels and the reduction of capitalized interest expense as the Q4000 and
Intrepid were in service for only the last nine month's of 2002.

Income Taxes. Income taxes increased to $19.0 million for 2003, compared
to $6.7 million in the prior year period due to increased profitability. The
effective rate increased to 36% in 2003 compared to 35% in 2002 due primarily to
provisions for foreign taxes. The Internal Revenue Service ("IRS") is in the
process of examining our income tax return for years 2001 and 2002, and the 2001
pre-acquisition income tax return for Canyon Offshore Inc. We believe the
ultimate resolution of these audits will not have a material adverse effect on
our financial condition, liquidity or results of operations.

Net Income. Net income of $32.8 million for 2003 was $20.4 million, or
165%, greater than 2002, as a result of the factors described above.

COMPARISON OF YEARS ENDED 2002 AND 2001

Revenues. During the year ended December 31, 2002, the Company's revenues
increased $75.6 million, or 33%, to $302.7 million compared to $227.1 million
for the year ended December 31, 2001 with the Marine Contracting segment
contributing all of the increase. Marine Contracting revenues increased to
$239.9 million for the year ended December 31, 2002 as compared to $163.7
million in the prior year. Our acquisitions of Canyon Offshore and Well Ops
(U.K.) Ltd. added $37.5 million and $21.4 million, respectively. The remainder
of the increase was due to the addition of three deepwater construction vessels:
the Q4000, the Intrepid and the Eclipse.

Oil and Gas Production revenue for the year ended December 31, 2002
decreased less than 1% to $62.8 million from $63.4 million during the prior
year. An increase in production, lead by the significant Shell and Hess
acquisitions made late in the third quarter of 2002, was offset by lower average
realized commodity prices. Oil and Gas Production increased 19% to 16.6 Bcfe in
2002 from 13.9 Bcfe during 2001, while our average realized commodity price
declined 15% to $3.71 per Mcfe ($3.39 per Mcf of natural gas and $25.54 per
barrel of oil) in 2002 as compared to $4.37 per Mcfe ($4.44 per Mcf of natural
gas and $24.54 per barrel of oil) in the prior year. Oil and condensate
represented 38% of ERT revenue in 2002 compared to 30% in 2001.

Gross Profit. Gross profit of $53.8 million for the year ended December
31, 2002 was $13.1 million, or 20%, below the $66.9 million gross profit
recorded in the prior year with both segments contributing to the decline.
Marine Contracting gross profit decreased $9.6 million, or 26%, to $27.0 million
during the year ended December 31, 2002 compared to $36.7 million during 2001.
Our DP vessels generated $8.6 million of gross profit, only 43% of the $20.1
million generated in the prior year, due in part to the charges recorded in the
fourth quarter related to a contract dispute. Margins for this segment decreased
to 11% for the year ended December 31, 2002 compared to 22% in 2001. While our
shallow water diving division margins held strong at 30% due to a large amount
of shelf repair work following Hurricane Lili, the DP fleet only contributed 7%
margins in 2002 compared to 25% in the prior year.

35

Oil and Gas Production gross profit decreased $3.5 million from $30.2
million in the year ended December 31, 2001 to $26.7 million for the year ended
December 31, 2002 due mainly to the aforementioned decrease in average realized
commodity prices. Margins declined to 43% during 2002 from 48% during 2001 due
to platform repairs and the time necessary for pipelines to return to full
production following Hurricane Lili.

Selling and Administrative Expenses. Selling and administrative expenses
of $32.8 million in 2002 were $11.5 million, or 54%, higher than the $21.3
million incurred during 2001. The increase is primarily due to the acquisitions
of Canyon and Well Ops (U.K.) Ltd. and a charge taken for the settlement of
litigation in the fourth quarter of 2002.

Other (Income) Expense. The Company reported net interest expense and
other of $2.0 million for the year ended December 31, 2002 in contrast to $1.3
million for the prior year. This increase is due to the increase in debt from
our capital program, which resulted in an additional $2.2 million in interest
expense, offset by a $1.1 million gain on our foreign currency hedge related to
the Well Ops (U.K.) Ltd. acquisition included in other income in the third
quarter of 2002.

Income Taxes. Income taxes decreased to $6.7 million for the year ended
December 31, 2002, compared to $15.5 million in the prior year due to decreased
profitability. Federal income taxes were provided at the statutory rate of 35%
in 2002. However, our deduction of Q4000 construction costs as Research and
Development expenditures for federal tax purposes resulted in CDI paying no
federal income taxes in 2002 and 2001. Since the deduction of Q4000 construction
costs affects financial and taxable income in different years, the entire 2002
and 2001 provisions for federal taxes were reflected as deferred income taxes.

Net Income. Net income of $12.4 million for the year ended December 31,
2002 was $16.6 million, or 57%, less than the $28.9 million earned in 2001 as a
result of factors described above.

ITEM 7. LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY AND CAPITAL RESOURCES

In August 2000, we closed the long-term MARAD financing for construction of
the Q4000. This U.S. Government guaranteed financing is pursuant to Title XI of
the Merchant Marine Act of 1936 which is administered by the Maritime
Administration. We refer to this debt as MARAD Debt. In January 2002, the
Maritime Administration agreed to expand the facility to $160 million to include
the modifications to the vessel which had been approved during 2001. We drew
$143.5 million on this facility. In January 2002, we acquired Canyon Offshore,
Inc.; in July 2002, we acquired the Well Operations Business Unit of Technip-
Coflexip and, in August 2002, ERT made two significant property acquisitions
(see further discussion below). These acquisitions significantly increased our
debt to total book capitalization ratio from 31% at December 31, 2001 to 40% at
December 31, 2002. In order to reduce this leverage, on January 8, 2003, CDI
completed the private placement of $25 million of a newly designated class of
cumulative convertible preferred stock (Series A-1 Cumulative Convertible
Preferred Stock, par value $0.01 per share) which is convertible into 833,334
shares of Cal Dive common stock at $30 per share. As of December 31, 2003 our
debt to total book capitalization declined to 35% and working capital increased
to $29.8 million from $14.3 million at December 31, 2002.

Operating Activities. Net cash provided by operating activities was $87.1
million during 2003, as compared to $65.2 million during 2002 due primarily to
an increase in profitability and a $26.0 million increase in depreciation and
amortization resulting from the aforementioned increase in production levels as
well as depreciation on additional DP vessels placed in service. This increase
was partially offset by funding from accounts receivable collections decreasing
$20.3 million as receivables have grown primarily as a result of increased ERT
production levels. Horizon Offshore, Inc. provided 5% of the Company's revenues
during 2003. Further, receivables included $11.0 million at December 31, 2003
related to Horizon.

Net cash provided by operating activities was $65.2 million during the year
ended December 31, 2002, as compared to $89.1 million during 2001. This decrease
was due mainly to decreased profitability and the

36

collection of a $10 million tax refund during 2001 from the IRS relating to the
deduction of Q4000 construction costs as research and development expenditures
for federal tax purposes. Depreciation and amortization also increased $10.2
million to $44.8 million due to the depreciation of new vessels placed in
service during 2002 and to increased depletion related to increased production
levels from ERT. This was offset by an increase in funding required for accounts
receivable collections during 2002 compared to 2001.

Investing Activities. Capital expenditures have consisted principally of
strategic asset acquisitions related to the purchase or construction of DP
vessels, acquisition of select businesses, improvements to existing vessels,
acquisition of oil and gas properties and construction of Deepwater Production
Facilities. We incurred $95.4 million of capital investments during 2003, $312.8
million during 2002 and $162.8 million in 2001.

We incurred $93.2 million of capital expenditures during the year ended
December 31, 2003 compared to $161.8 million during the prior year. Included in
the capital expenditures during 2003 was $17.5 million for the purchase of ROV
units to support the Canyon MSA agreement with Technip/Coflexip to provide
robotic and trenching services, $39.6 million related to Gunnison development
costs, including the spar, as well as $39.7 million relating to ERT's 2003 well
exploitation program. Included in capital expenditures in 2002 was $29.1 million
for the construction of the Q4000 and $20.8 million relating to the Intrepid DP
conversion and Eclipse upgrade. Also included in 2002 was over $25 million in
ERT offshore property acquisitions (see discussion below) as well as
approximately $53 million related to Gunnison development costs, including the
spar.

Included in the $151.3 million of capital expenditures in 2001 was $53
million for the construction of the Q4000, $33 million for the conversion of the
Intrepid, $40 million relating to the purchase of two DP vessels (the 240-foot
by 52-foot Mystic Viking and the 370-foot by 67-foot Eclipse), and expenditures
of $20 million for initial Gunnison development costs and the ERT 2001 Well
Enhancement Program. In addition, in March 2001, CDI acquired substantially all
of the assets of Professional Divers of New Orleans in exchange for $11.5
million. The assets purchased included the 165-foot four-point moored DSV the
Mr. Sonny, three utility vessels and associated diving equipment including two
saturation diving systems. This acquisition was accounted for as a purchase with
the acquisition price of $11.5 million being allocated to the assets acquired
and liabilities assumed based upon their estimated fair values with the balance
of the purchase price ($2.8 million) being recorded as goodwill.

In March 2003, ERT acquired additional interests, ranging from 45% to 84%,
in four fields acquired last year, enabling ERT to take over as operator of one
field. ERT paid $858,000 in cash and assumed Exxon/ Mobil's pro-rata share of
the abandonment obligation for the acquired interests.

On August 30, 2002, ERT acquired the 74.8% working interest of Shell
Exploration & Production Company in the South Marsh Island 130 (SMI 130) field.
ERT paid $10.3 million in cash and assumed Shell's pro-rata share of the related
decommissioning liability. ERT also completed the purchase of interests in seven
Gulf of Mexico fields from Amerada Hess including its 25% ownership position in
SMI 130 for $9.3 million in cash and assumption of Amerada Hess' pro-rata share
of the related decommissioning liability. As a result, ERT is the operator with
an effective 100% working interest in that field.

In July 2002, CDI purchased the Subsea Well Operations Business Unit of CSO
Ltd., a wholly owned subsidiary of Technip-Coflexip, for approximately $72.0
million ($68.6 million cash and $3.4 million deferred tax liability assumption).

In June 2002, ERT acquired a package of offshore properties from Williams
Exploration and Production. ERT paid $4.9 million and assumed the pro-rata share
of the abandonment obligation for the acquired interests. The blocks purchased
represent an average 30% net working interest in 26 Gulf of Mexico leases. In
April 2002, ERT acquired a 100% interest in East Cameron Block 374, including
existing wells, equipment and improvements. The property, located in 425 feet of
water, was jointly owned by Murphy Exploration & Production Company and Callon
Petroleum Operating Company. Terms included a cash payment of approximately $3
million to reimburse the owners for the inception-to-date cost of the subsea
wellhead and umbilical and an overriding royalty interest in future production.
Cal Dive completed the temporarily

37

abandoned number one well and performed a subsea tie-back to host platform. The
cost of completion and tie-back was approximately $7 million with first
production occurring in August 2002.

In January 2002, CDI purchased Canyon, a supplier of remotely operated
vehicles (ROVs) and robotics to the offshore construction and telecommunications
industries. CDI purchased Canyon for cash of $52.8 million, the assumption of
$9.0 million of Canyon debt (offset by $3.1 million of cash acquired), 181,000
shares of our common stock (143,000 shares of which we purchased as treasury
shares during the fourth quarter of 2001) and a commitment to purchase the
redeemable stock in Canyon at a price to be determined by Canyon's performance
during the years 2002 through 2004 from continuing employees at a minimum
purchase price of $13.53 per share.

In June 2002, CDI, along with GulfTerra Energy Partners L.P. ("GulfTerra"),
formed Deepwater Gateway, L.L.C. (a 50/50 venture) to design, construct,
install, own and operate a tension leg platform ("TLP") production hub primarily
for Anadarko Petroleum Corporation's Marco Polo field discovery in the Deepwater
Gulf of Mexico. Our share of the construction costs is estimated to be
approximately $123 million (approximately $110 million of which had been
incurred as of December 31, 2003). In August 2002, the Company along with
GulfTerra, completed a non-recourse project financing for this venture, terms of
which include a minimum equity investment for CDI of $33 million, all of which
had been paid as of December 31, 2003, and is recorded as Investment in
Production Facilities in the accompanying consolidated balance sheet. Terms of
the financing also require CDI to guarantee a balloon payment at the end of the
financing term in 2008 (estimated to be $22.5 million). The Company has not
recorded any liability for this guarantee as management believes that it is
unlikely the Company will be required to pay the balloon payment.

In April 2000, ERT acquired a 20% working interest in Gunnison, a Deepwater
Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corp. Consistent with CDI's
philosophy of avoiding exploratory risk, financing for the exploratory costs of
approximately $20 million was provided by an investment partnership (OKCD
Investments, Ltd. or "OKCD"), the investors of which include current and former
CDI senior management, in exchange for a revenue interest that is an overriding
royalty interest of 25% of CDI's 20% working interest. CDI provided no
guarantees to the investment partnership. The Board of Directors established
three criteria to determine a commercial discovery and the commitment of Cal
Dive funds: 75 million barrels (gross) of reserves, estimated development costs
of $500 million consistent with 75 MBOE, and a CDI estimated shareholder return
of no less than 12%. Kerr-McGee, the operator, drilled several exploration wells
and sidetracks in 3,200 feet of water at Garden Banks 667, 668 and 669 (the
Gunnison prospect) and encountered significant potential reserves resulting in
the three criteria being achieved during 2001. The exploratory phase was
expanded to ensure field delineation resulting in the investment partnership,
which assumed the exploratory risk, funding approximately $20 million of
exploratory drilling costs. With the sanctioning of a commercial discovery, the
Company funded ongoing development and production costs. Cal Dive's share of
such project development costs is estimated in a range of $110 million to $115
million ($104 million of which had been incurred by December 31, 2003) with over
half of that for construction of the spar which was placed in service in
December 2003. The Company's Chief Executive Officer, as a Class A limited
partner of OKCD, personally owns approximately 57% of the partnership. Other
executive officers of the Company own approximately 6% combined, of the
partnership. OKCD has also awarded Class B limited partnership interests to key
CDI employees. See footnote 8 to the Company's Consolidated Financial Statements
included herein for discussion of the financing related to the spar
construction. Production began in December 2003.

Financing Activities. We have financed seasonal operating requirements and
capital expenditures with internally generated funds, borrowings under credit
facilities, the sale of common stock and project financings. Our largest debt
financing has been the MARAD debt. During 2001 and 2002, we borrowed $59.5
million and $43.9 million, respectively, on this facility bringing the total to
$142.1 million at December 31, 2002. No draws were made in 2003 on this
facility. The MARAD debt is payable in equal semi-annual installments beginning
in August 2002 and maturing 25 years from such date. We made two such payments
during 2003 totaling $2.8 million. It is collateralized by the Q4000, with Cal
Dive guaranteeing 50% of the debt, and bears an interest rate which currently
floats at a rate approximating AAA Commercial Paper yields plus 20 basis points
(approximately 1.33% as of December 31, 2003). For a period up to ten years from
delivery of the vessel in April 2002, the Company has options to lock in a fixed
rate. In accordance with the MARAD debt
38

agreements, we are required to comply with certain covenants and restrictions,
including the maintenance of minimum net worth, working capital and
debt-to-equity requirements. As of December 31, 2003, we were in compliance with
these covenants.

The Company has a $70 million revolving credit facility due in 2005. This
facility is collateralized by accounts receivable and certain of the Company's
Marine Contracting vessels, bears interest at LIBOR plus 125-250 basis points
depending on CDI leverage ratios (approximately 3.0% as of December 31, 2003)
and, among other restrictions, includes three financial covenants (cash flow
leverage, minimum interest coverage and fixed charge coverage). As of December
31, 2003, the Company had drawn $30.2 million (a $22.4 million reduction from
December 31, 2002) under this revolving credit facility and was in compliance
with these covenants.

The Company has a $35 million term loan facility which was obtained to
assist CDI in funding its portion of the construction costs of the spar for the
Gunnison field. The loan is payable in quarterly installments of $1.75 million
for three years after delivery of the spar (which was December 2003) with the
remaining $15.75 million due at the end of the three years (2006). The facility
bears interest at LIBOR plus 225-300 basis points depending on CDI leverage
ratios (approximately 3.6% as of December 31, 2003) and includes, among other
restrictions, three financial covenants (cash flow leverage, minimum interest
coverage and debt to total book capitalization). The Company was in compliance
with these covenants as of December 31, 2003.

In August 2003, Canyon Offshore, Ltd. (a U.K. subsidiary -- "COL"),, with a
parent guarantee from Cal Dive, completed a capital lease with a bank
refinancing the construction costs of a newbuild 750 horsepower trenching unit
and a ROV. COL received proceeds of $12 million for the assets and agreed to pay
the bank sixty monthly installment payments of $217,174 (resulting in an
implicit interest rate of 3.29%). COL has an option to purchase the assets at
the end of the lease term for $1. The proceeds were used to reduce the Company's
revolving credit facility, which had initially funded the construction costs of
the assets. This transaction has been accounted for as a capital lease under
SFAS No. 13, Accounting for Leases, with the present value of the lease
obligation (and corresponding asset) being reflected on the Company's
consolidated balance sheet during the third quarter of 2003.

In January 2003, CDI completed the private placement of $25 million of
preferred stock which is convertible into 833,334 shares of CDI common stock at
$30 per share. The preferred stock was issued to a private investment firm. The
preferred stock holder has the right to purchase as much as $30 million in
additional preferred stock for a period of two years beginning in July 2003. The
conversion price of the additional preferred stock will equal 125% of the then
prevailing price of Cal Dive common stock, subject to a minimum conversion price
of $30 per common share. The preferred stock has a minimum annual dividend rate
of 4%, or LIBOR plus 150 basis points if greater, payable quarterly in cash or
common shares at Cal Dive's option. CDI paid these dividends in 2003 on the last
day of the respective quarters in cash. After the second anniversary, the holder
may redeem the value of its original investments in the preferred shares to be
settled in common stock at the then prevailing market price or cash at the
discretion of the Company. Under certain conditions, the holder could redeem its
investment prior to the second anniversary. Prior to the conversion, common
shares issuable will be assessed for inclusion in the weighted average shares
outstanding for the Company's diluted earnings per share under the if converted
method based on the Company's common share price at the beginning of the
applicable period.

In April 2003, the Company purchased approximately one-third of the
redeemable stock in Canyon related to the Canyon purchase (see Investing
Activities above and footnote 5 to the Company's Consolidated Financial
Statements included herein for discussion of the Canyon acquisition) at the
minimum purchase price of $13.53 per share ($2.7 million).

In May 2002, CDI sold 3.4 million shares of primary common stock for $23.16
per share, along with 517,000 additional shares to cover over-allotments. Net
proceeds to the Company of approximately $87.2 million were used for the
Coflexip Well Operations acquisition, ERT acquisitions and to retire debt under
the Company's revolving line of credit.

39

During 2003 and 2002, we made payments of $2.4 million and $5.2 million
separately on capital leases related to Canyon. The only other financing
activity during 2003, 2002 and 2001 involved the exercise of employee stock
options ($3.6 million, $5.9 million and $4.1 million, respectively).

The following table summarizes our contractual cash obligations as of
December 31, 2003 and the scheduled years in which the obligation are
contractually due:

- ---------------

(A) Excludes CDI guarantee of balloon payment due in 2008 on non-recourse
project financing (estimated to be $22.5 million).

In addition, in connection with our business strategy, we evaluate
acquisition opportunities (including additional vessels as well as interest in
offshore natural gas and oil properties and production facilities). We believe
that internally-generated cash flow, borrowings under existing credit facilities
and use of project financings along with other debt and equity alternatives will
provide the necessary capital to meet these obligations and achieve our planned
growth.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is currently exposed to market risk in three major areas:
interest, commodity prices and foreign currency. Because the majority of the
Company's debt at December 31, 2003 was based on floating rates, changes in
interest would, assuming all other things equal, have a minimal impact on the
fair market value of the debt instruments but every 100 basis points move in
interest rates would result in $2.2 million of annualized interest expense or
savings, as the case may be, to the Company.

COMMODITY PRICE RISK

The Company has utilized derivative financial instruments with respect to a
portion of 2003 and 2002 oil and gas production to achieve a more predictable
cash flow by reducing its exposure to price fluctuations. The Company does not
enter into derivative or other financial instruments for trading purposes.

40

As of December 31, 2003, the Company has the following volumes under
derivative contracts related to its oil and gas producing activities:

Changes in NYMEX oil and gas strip prices would, assuming all other things
being equal, cause the fair market value of these instruments to increase or
decrease.

Subsequent to December 31, 2003, the Company entered into additional oil
swaps for the period September through December 2004. The contracts cover 15
MBbl per month at $29.50. The Company also entered into additional natural gas
costless collars for the period July through December 2004. The contracts cover
100,000 MMBtu per month at a weighted average price of $5.00 to $6.25.

FOREIGN CURRENCY EXCHANGE RATES

Because we operate in various oil and gas exploration and production
regions in the world, we conduct a portion of our business in currencies other
than the U.S. dollar (primarily with respect to Well Ops (U.K.) Limited). The
functional currency for Well Ops (U.K.) Limited is the applicable local currency
(British Pound). Although the revenues are denominated in the local currency,
the effects of foreign currency fluctuations are partly mitigated because local
expenses of such foreign operations also generally are denominated in the same
currency. The impact of exchange rate fluctuations during the years ended
December 31, 2003 and 2002 did not have a material effect on reported amounts of
revenues or net income.

Assets and liabilities of Well Ops (U.K.) Limited are translated using the
exchange rates in effect at the balance sheet date, resulting in translation
adjustments that are reflected in accumulated other comprehensive income (loss)
in the shareholders' equity section of our balance sheet. Approximately 12% of
our assets are impacted by changes in foreign currencies in relation to the U.S.
dollar. We recorded gains of $5.0 million and $2.5 million, net of taxes, to our
equity account for the years ended December 31, 2003 and 2002 to reflect the net
impact of the decline of the U.S. dollar against the British Pound.

Canyon Offshore, the Company's ROV subsidiary, has operations in the United
Kingdom and Southeast Asia sectors. Canyon conducts the majority of its affairs
in these regions in U.S. dollars which it considers the functional currency.
When currencies other than the U.S. dollar are to be paid or received, the
resulting gain or loss from translation is recognized in the statements of
operations. These amounts for the years ended December 31, 2003 and 2002,
respectively, were not material to the Company's results of operations or cash
flows.

41

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

42

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Shareholders of
Cal Dive International, Inc.:

We have audited the accompanying consolidated balance sheets of Cal Dive
International, Inc. and Subsidiaries as of December 31, 2003 and 2002 and the
related consolidated statements of operations, shareholders' equity and cash
flows for the years then ended. 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. The consolidated
financial statements of Cal Dive International, Inc. as of December 31, 2001 and
for the year then ended were audited by other auditors who have ceased
operations. Those auditors expressed an unqualified opinion on those
consolidated financial statements in their report dated February 18, 2002.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Cal Dive
International, Inc. and Subsidiaries at December 31, 2003 and 2002 and the
consolidated results of their operations and their cash flows for the years then
ended in conformity with accounting principles generally accepted in the United
States.

As discussed in Note 2 to the consolidated financial statements, the
Company adopted Statement of Financial Accounting Standards No. 142, "Goodwill
and Other Intangible Assets" in 2002.

As discussed in Note 2 to the consolidated financial statements, the
Company adopted Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" and Statement of Financial Accounting
Standards No. 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity" in 2003.

ERNST & YOUNG LLP

Houston, Texas
February 23, 2004

43

NOTE: THE REPORT OF ARTHUR ANDERSEN LLP PRESENTED BELOW IS A COPY OF A
PREVIOUSLY ISSUED ARTHUR ANDERSEN LLP REPORT AND SAID REPORT HAS NOT BEEN
REISSUED BY ARTHUR ANDERSEN LLP NOR HAS ARTHUR ANDERSEN LLP PROVIDED A
CONSENT TO THE INCLUSION OF ITS REPORT IN THIS FORM 10-K.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Shareholders of
Cal Dive International, Inc.:

We have audited the accompanying consolidated balance sheets of Cal Dive
International Inc. (a Minnesota corporation) and subsidiaries as of December 31,
2001 and 2000, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 2001. 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 in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Cal Dive International,
Inc., and subsidiaries as of December 31, 2001 and 2000, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States.

ARTHUR ANDERSEN LLP

Houston, Texas
February 18, 2002

44

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2003 AND 2002

The accompanying notes are an integral part of these consolidated financial
statements.
45

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

The accompanying notes are an integral part of these consolidated financial
statements.
46

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

The accompanying notes are an integral part of these consolidated financial
statements.
47

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

The accompanying notes are an integral part of these consolidated financial
statements.
48

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

Cal Dive International, Inc. (Cal Dive, CDI or the Company), headquartered
in Houston, Texas, is an energy services company with operations in two primary
business segments: Marine Contracting and Oil & Gas Production. Within its
Marine Contracting segment, CDI operates primarily in the Gulf of Mexico (Gulf),
and recently in the North Sea and Asia/Pacific, with services that cover the
lifecycle of an offshore oil or gas field. CDI's current diversified fleet of 22
vessels and 25 remotely operated vehicles (ROVs) and trencher systems perform
services that support drilling, well completion, intervention, construction and
decommissioning projects involving pipelines, production platforms, risers and
subsea production systems. The Company also has a significant investment in
offshore oil and gas production as well as production facilities. Operations in
the Production Facilities segment should begin in 2004 with Marco Polo coming
online. CDI's customers include major and independent oil and gas producers,
pipeline transmission companies and offshore engineering and construction firms.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

The accompanying consolidated financial statements include the accounts of
the Company and its majority owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated. The Company accounts for its 50%
interest in Deepwater Gateway, L.L.C. using the equity method of accounting as
the Company does not have voting or operational control of this entity. The
Company currently believes that it has no involvement with any variable interest
entity covered by the scope of FASB Interpretation ("FIN") No. 46, Consolidation
of Variable Interest Entities (see "Accounting Principles Not Yet Adopted"
below).

USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. On an ongoing basis the Company evaluates its estimates
including those related to bad debts, investments, intangible assets and
goodwill, property plant and equipment, decommissioning liabilities, income
taxes, worker's compensation insurance and contingent liabilities. The Company
bases its estimates on historical experience and on various other assumptions
that are believed to be reasonable under the circumstances, the results of which
form the basis for making judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources. Actual results
could differ from those estimates.

GOODWILL

The Company tests for the impairment of goodwill on at least an annual
basis. The Company's goodwill impairment test involves a comparison of the fair
value of each of the Company's reporting units with its carrying amount. The
fair value is determined using discounted cash flows and other market-related
valuation models, such as earnings multiples and comparable asset market values.
Prior to 2002 goodwill was amortized on a straight line basis over 25 years. In
2002 the Company discontinued the amortization of goodwill. The Company
completed its annual goodwill impairment test as of November 1, 2003. The
Company's goodwill impairment test involves a comparison of the fair value of
each of the Company's reporting units with its carrying amount. All of the
Company's goodwill as of December 31, 2003 and 2002 related to its Marine
Contracting segment. None of the Company's goodwill was impaired based on the
impairment test performed as of November 1, 2003. The Company will continue to
test its goodwill annually on a consistent measurement

49

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

date unless events occur or circumstances change between annual tests that would
more likely than not reduce the fair value of a reporting unit below its
carrying amount.

PROPERTY AND EQUIPMENT

Property and equipment, both owned and under capital leases, are recorded
at cost. Depreciation is provided primarily on the straight-line method over the
estimated useful lives of the assets.

All of the Company's interests in oil and gas properties are located
offshore in United States waters. The Company follows the successful efforts
method of accounting for its interests in oil and gas properties. Under the
successful efforts method, the costs of successful wells and leases containing
productive reserves are capitalized. Costs incurred to drill and equip
development wells, including unsuccessful development wells, are capitalized.

Energy Resource Technology, Inc. ("ERT") acquisitions of producing offshore
properties are recorded at the value exchanged at closing together with an
estimate of its proportionate share of the discounted decommissioning liability
assumed in the purchase based upon its working interest ownership percentage. In
estimating the decommissioning liability assumed in offshore property
acquisitions, the Company performs detailed estimating procedures, including
engineering studies. See Accounting Principles Adopted in 2003 below in this
footnote for discussion on accounting for decommissioning liabilities. All
capitalized costs are amortized on a unit-of-production basis (UOP) based on the
estimated remaining oil and gas reserves. Properties are periodically assessed
for impairment in value, with any impairment charged to expense.

The following is a summary of the components of property and equipment
(dollars in thousands):

Construction in progress as of December 31, 2002 included costs incurred
related to construction of the spar at Gunnison (see notes 4 and 8). The spar at
Gunnison was placed in service in December 2003 and is included in offshore
leases and equipment. The Company capitalized interest totaling $3.4 million,
$4.4 million and $1.9 million during the years ended December 31, 2003, 2002 and
2001, respectively.

The cost of repairs and maintenance of vessels and equipment is charged to
operations as incurred, while the cost of improvements is capitalized. Total
repair and maintenance charges were $14.7 million, $11.5 million and $8.5
million for the years ended December 31, 2003, 2002 and 2001, respectively.

For long-lived assets to be held and used, excluding goodwill, the Company
bases its evaluation on impairment indicators such as the nature of the assets,
the future economic benefit of the assets, any historical or future
profitability measurements and other external market conditions or factors that
my be present. If such impairment indicators are present or other factors exist
that indicate that the carrying amount of the asset may not be recoverable, the
Company determines whether an impairment has occurred through the use of an
undiscounted cash flows analysis of the asset at the lowest level for which
identifiable cash flows exist. If an impairment has occurred, the Company
recognizes a loss for the difference between the carrying amount and the fair
value of the asset. The fair value of the asset is measured using quoted market
prices or, in the absence of quoted market prices, is based on an estimate of
discounted cash flows. Assets are classified as held for sale when the Company
has a plan for disposal of certain assets and those assets meet the held for
sale criteria.

50

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

DEFERRED DRYDOCK CHARGES

The Company accounts for regulatory (U.S. Coast Guard, American Bureau of
Shipping and Det Norske Veritas) related drydock inspection and certification
expenditures by capitalizing the related costs and amortizing them over the
30-month period between regulatory mandated drydock inspections and
certification. During the years ended December 31, 2003, 2002 and 2001, drydock
amortization expense was $4.1 million, $4.9 million and $3.1 million,
respectively.

FOREIGN CURRENCY

The functional currency for the Company's foreign subsidiary, Well Ops
(U.K.) Limited, is the applicable local currency (British Pound). Results of
operations for this subsidiary are translated into U.S. dollars using average
exchange rates during the period. Assets and liabilities of this foreign
subsidiary are translated into U.S. dollars using the exchange rate in effect at
the balance sheet date and the resulting translation adjustment, which was a
gain of $5.0 million and $2.5 million, net of taxes of $2.8 million and $1.4
million, in 2003 and 2002, respectively, is included as accumulated other
comprehensive income, a component of shareholders' equity. All foreign currency
transaction gains and losses are recognized currently in the statements of
operations. These amounts for the years ended December 31, 2003 and 2002 were
not material to the Company's results of operations or cash flows.

Canyon Offshore, the Company's ROV subsidiary, has operations in the United
Kingdom and Southeast Asia sectors. Canyon conducts the majority of its affairs
in these regions in U.S. dollars which it considers the functional currency.
When currencies other than the U.S. dollar are to be paid or received, the
resulting gain or loss from translation is recognized in the statements of
operations.

These amounts for the years ended December 31, 2003 and 2002 were not
material to the Company's results of operations or cash flows.

ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES

The Company's price risk management activities involve the use of
derivative financial instruments to hedge the impact of market price risk
exposures primarily related to its oil and gas production. All derivatives are
reflected in the Company's balance sheet at fair market value.

There are two types of hedging activities: hedges of cash flow exposure and
hedges of fair value exposure. The Company engages primarily in cash flow
hedges. Hedges of cash flow exposure are entered into to hedge a forecasted
transaction or the variability of cash flows to be received or paid related to a
recognized asset or liability. Changes in the derivative fair values that are
designated as cash flow hedges are deferred to the extent that they are
effective and are recorded as a component of accumulated other comprehensive
income until the hedged transactions occur and are recognized in earnings. The
ineffective portion of a cash flow hedge's change in value is recognized
immediately in earnings in oil and gas production revenues.

The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objectives,
strategies for undertaking various hedge transactions and the methods for
assessing and testing correlation and hedge ineffectiveness. All hedging
instruments are linked to the hedged asset, liability, firm commitment or
forecasted transaction. The Company also assesses, both at the inception of the
hedge and on an on-going basis, whether the derivatives that are used in the
hedging transactions are highly effective in offsetting changes in cash flows of
its hedged items. The Company discontinues hedge accounting if it determines
that a derivative is no longer highly effective as a hedge, or it is probable
that a hedged transaction will not occur. If hedge accounting is discontinued,
deferred gains or losses on the hedging instruments are recognized in earnings
immediately.

51

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The market value of hedging instruments reflects the Company's best
estimate and is based upon exchange or over-the-counter quotations whenever they
are available. Quoted valuations may not be available due to location
differences or terms that extend beyond the period for which quotations are
available. Where quotes are not available, the Company utilizes other valuation
techniques or models to estimate market values. These modeling techniques
require the Company to make estimations of future prices, price correlation and
market volatility and liquidity. The Company's actual results may differ from
its estimates, and these differences can be positive or negative.

During 2003 and 2002, the Company entered into various cash flow hedging
swap and costless collar contracts to fix cash flows relating to a portion of
the Company's oil and gas production. All of these qualified for hedge
accounting and none extended beyond a year and a half. The aggregate fair value
of the hedges was a liability of $2.2 million and $4.1 million as of December
31, 2003 and 2002, respectively. For the years ended December 31, 2003 and 2002
the Company recorded a $1.2 million gain, net of taxes of $.7 million, and a
loss of $2.6 million, net of taxes of $1.4 million, respectively, in other
comprehensive income (loss) within shareholders' equity as these hedges were
highly effective. The balance in the fair value hedge adjustments account is
recognized in earnings when the hedged item is sold.

As of December 31, 2003, the Company has the following volumes under
derivative contracts related to its oil and gas producing activities:

Subsequent to December 31, 2003, the Company entered into additional oil
swaps for the period September through December 2004. The contracts cover 15
MBbl per month at $29.50. The Company also entered into additional natural gas
costless collars for the period July through December 2004. The contracts cover
100,000 MMBtu per month at a weighted average price of $5.00 to $6.25.

In June 2002, CDI signed an agreement with Coflexip to acquire the Subsea
Well Operations Business Unit for 44.8 million British pounds (which at the time
equaled $67.5 million) which subsequently closed in July 2002. CDI entered into
a foreign currency forward contract to lock in the British Pound to U.S. dollar
exchange rate. The Company accounted for this transaction with changes in its
fair value reported in earnings. Accordingly, a $1.1 million gain was recorded
in other income for the year ended December 31, 2002 as a result of the change
in market value of the contract as of June 30, 2002. This contract settled in
July 2002 for $1.1 million.

52

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

EARNINGS PER SHARE

Basic EPS is computed by dividing the net income available to common
shareholders by the weighted-average shares of outstanding common stock. The
calculation of diluted EPS is similar to basic EPS except that the denominator
includes dilutive common stock equivalents and the income included in the
numerator excludes the effects of the impact of dilutive common stock
equivalents, if any. The computation of the basic and diluted per share amounts
for the Company was as follows (in thousands, except per share amounts):

Stock options to purchase approximately 1,027,000 shares, 260,000 shares
and 115,000 shares for the years ended December 31, 2003, 2002 and 2001,
respectively, were not dilutive and, therefore, were not included in the
computations of diluted income per common share amounts. In addition,
approximately 1.1 million shares attributable to the convertible preferred stock
were excluded from the year ended December 31, 2003 calculation of diluted EPS,
as the effect would be anti-dilutive.

53

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STOCK BASED COMPENSATION PLANS

In December 2002, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 148, Accounting for
Stock-Based Compensation Transition and Disclosure ("SFAS No. 148"), to provide
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. As permitted under
SFAS No. 123, Accounting for Stock-Based Compensation, the Company continues to
use the intrinsic value method of accounting established by Accounting
Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, to
account for its stock-based compensation programs. Accordingly, no compensation
expense is recognized when the exercise price of an employee stock option is
equal to the Common Share market price on the grant date. The following table
reflects the Company's pro forma results if SFAS No. 123 had been used for the
accounting of these plans (in thousands, except per share amounts):

For the purposes of pro forma disclosures, the fair value of each option
grant is estimated on the date of grant using the Black-Scholes option pricing
model with the following weighted average assumptions used: expected dividend
yields of 0 percent; expected lives ranging from three to ten years, risk-free
interest rate assumed to be 4.0 percent in 2003 and 2002, and 4.5 percent in
2001, and expected volatility to be 56 percent in 2003, 59 percent in 2002, and
61 percent in 2001. The fair value of shares issued under the Employee Stock
Purchase Plan was based on the 15% discount received by the employees. The
weighted average per share fair value of the options granted in 2003, 2002 and
2001 was $12.74, $15.20, and $14.47, respectively. The estimated fair value of
the options is amortized to pro forma expense over the vesting period.

REVENUE RECOGNITION

The Company earns the majority of marine contracting revenues during the
summer and fall months. Revenues are derived from billings under contracts
(which are typically of short duration) that provide for either lump-sum turnkey
charges or specific time, material and equipment charges which are billed in
accordance with the terms of such contracts. The Company recognizes revenue as
it is earned at estimated collectible amounts. Revenues generated from specific
time, materials and equipment charges contracts are generally earned over a
dayrate basis and recognized as amounts are earned in accordance with contract
terms. Revenues generated in the pre-operation mode before a contract commences
are deferred and recognized on a

54

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

straight line basis in accordance with contract terms. Direct and incremental
costs associated with pre-operation activities are similarly deferred and
recognized over the estimated contract period.

Revenue on significant turnkey contracts is recognized on the
percentage-of-completion method based on the ratio of costs incurred to total
estimated costs at completion, or achievement of certain contractual milestones
if provided for in the contract. Contract price and cost estimates are reviewed
periodically as work progresses and adjustments are reflected in the period in
which such estimates are revised. Provisions for estimated losses on such
contracts are made in the period such losses are determined. Unbilled revenue
represents revenue attributable to work completed prior to year-end which has
not yet been invoiced. All amounts included in unbilled revenue at December 31,
2003 are expected to be billed and collected within one year.

The Company records revenues from the sales of crude oil and natural gas
when delivery to the customer has occurred and title has transferred. This
occurs when production has been delivered to a pipeline or a barge lifting has
occurred. The Company may have an interest with other producers in certain
properties. In this case the Company uses the entitlements method to account for
sales of production. Under the entitlements method the Company may receive more
or less than its entitled share of production. If the Company receives more than
its entitled share of production, the imbalance is treated as a liability. If
the Company receives less than its entitled share, the imbalance is recorded as
an asset.

REVENUE ALLOWANCE ON GROSS AMOUNTS BILLED

The Company bills for work performed in accordance with the terms of the
applicable contract. The gross amount of revenue billed will include not only
the billing for the original amount quoted for a project but also include
billings for services provided which the Company believes are allowed under the
terms of the related contract but are outside the scope of the original quote.
The Company establishes a revenue allowance for these additional billings based
on its collections history if conditions warrant such a reserve.

MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK

The market for the Company's products and services is primarily the
offshore oil and gas industry. Oil and gas companies make capital expenditures
on exploration, drilling and production operations offshore, the level of which
is generally dependent on the prevailing view of the future oil and gas prices,
which have been characterized by significant volatility. The Company's customers
consist primarily of major, well-established oil and pipeline companies and
independent oil and gas producers. The Company performs ongoing credit
evaluations of its customers and provides allowances for probable credit losses
when necessary. The percent of consolidated revenue of major customers was as
follows: 2003 -- Shell Trading (US) Company (10%); Petrocom Energy Group, Ltd.
(10%); 2002 -- BP Trinidad & Tobago LLC (11%); and 2001 -- Enron Corporation
(10%). Marine contracting revenues from Horizon Offshore, Inc. were 5%, 10% and
18% of consolidated revenues during the years ended December 31, 2003, 2002 and
2001, respectively. Further, net trade receivables, from Horizon totaled $11.0
million and $6.9 million at December 31, 2003 and 2002, respectively.

INCOME TAXES

Deferred income taxes are based on the differences between financial
reporting and the tax bases of assets and liabilities in accordance with SFAS
No. 109, Accounting for Income Taxes. The statement requires, among other
things, the use of the liability method of computing deferred income taxes. The
liability method is based on the amount of current and future taxes payable
using tax rates and laws in effect at the balance sheet date. Income taxes have
been provided based upon the tax laws and rates in the countries in which
operations are conducted and income is earned. A valuation allowance for
deferred tax assets is recorded when it is more likely than not that some or all
of the benefit from the deferred tax asset will not be realized.
55

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STATEMENT OF CASH FLOW INFORMATION

The Company defines cash and cash equivalents as cash and all highly liquid
financial instruments with original maturities of less than three months. The
Company had $2.4 million of restricted cash as of December 31, 2003, of which
$2.3 million represented amounts securing a performance bond which management
believes will be released during 2004. During the years ended December 31, 2003,
2002 and 2001, the Company made cash payments for interest charges, totaling
$2.7 million, $811,000 and $662,000, respectively, net of interest capitalized.
Further, the Company made no cash payments for federal income taxes during the
years ended December 31, 2003, 2002 and 2001.

ACCOUNTING PRINCIPLES ADOPTED IN 2003

On January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset
Retirement Obligations, which addresses the financial accounting and reporting
obligations and retirement costs related to the retirement of tangible
long-lived assets. Among other things, SFAS No. 143 requires oil and gas
companies to reflect decommissioning liabilities on the face of the balance
sheet at fair value on a discounted basis. Prior to January 1, 2003, the Company
reflected this liability on the balance sheet on an undiscounted basis.

The adoption of SFAS No. 143 resulted in a cumulative effect adjustment as
of January 1, 2003 to record (i) a $33.1 million decrease in the carrying values
of proved properties, (ii) a $7.4 million decrease in accumulated depreciation,
depletion and amortization of property and equipment, (iii) a $26.5 million
decrease in decommissioning liabilities and (iv) a $0.3 million increase in
deferred income tax liabilities. The net impact of items (i) through (iv) was to
record a gain of $0.5 million, net of tax, as a cumulative effect adjustment of
a change in accounting principle in the Company's consolidated statements of
operations upon adoption on January 1, 2003. The Company has no material assets
that are legally restricted for purposes of settling its decommissioning
liabilities.

The pro forma effects of the application of SFAS No. 143 as if the
statement had been adopted on January 1, 2002 are presented below (in thousands,
except per share amounts):

56

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table describes the changes in the Company's asset retirement
obligations for the year ended 2003 (in thousands):

Asset retirement obligation at December 31, 2002............ $ 92,420
Cumulative effect adjustment................................ (26,527)
--------
Asset retirement obligation at January 1, 2003.............. 65,893
Liability incurred during the period........................ 6,449
Liabilities settled during the period....................... (5,646)
Revision in estimated cash flows............................ 8,118
Accretion expense........................................... 3,600
--------
Asset retirement obligation at December 31, 2003............ $ 78,414
========

The pro forma asset retirement obligation liability balances as if SFAS No.
143 had been adopted January 1, 2002 are as follows (in thousands):

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities ("SFAS No. 149"). SFAS No. 149
amended and clarified the accounting for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities under SFAS No. 133. SFAS No. 149 was generally effective for
contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003. The adoption of SFAS No. 149 did
not have a material effect on the Company's consolidated financial statements.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity ("SFAS No.
150"). SFAS No. 150 requires that certain financial instruments, which under
previous guidance were accounted for as equity, must now be accounted for as
liabilities. The financial instruments affected include mandatorily redeemable
stock, certain financial instruments that require or may require the issuer to
buy back some of its shares in exchange for cash or other assets and certain
obligations that can be settled with shares of stock. SFAS No. 150 was effective
for all financial instruments entered into or modified after May 31, 2003 and
was adopted by the Company effective July 1, 2003. As a result of this adoption,
the Company reclassified the $4.9 million of Redeemable Stock in Subsidiary (see
discussion in Note 5) from mezzanine classification (i.e., between liabilities
and shareholders' equity on the balance sheet) to long-term debt, along with the
applicable amount in current maturities of long-term debt. The adoption had no
other impact on the Company's consolidated financial statements.

ACCOUNTING PRINCIPLES NOT YET ADOPTED

In January 2003, FIN No. 46 was issued which requires companies that
control another entity through interests other than voting interests to
consolidate the controlled entity. FIN No. 46 applies immediately to variable
interest entities created after January 31, 2003. For variable interest entities
created before February 1, 2003, FIN No. 46 is to be applied no later than the
end of the first reporting period ending after March 15, 2004. The
Interpretation requires certain disclosures in financial statements issued after
January 31, 2003, if it is reasonably possible that the Company will consolidate
or disclose information about variable interest entities when the Interpretation
becomes effective. The Company currently believes that it has no involvement
with any variable interest entity covered by the scope of FIN No 46.

57

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

OTHER MATTERS

The FASB's Emerging Issues Task Force ("EITF") currently is deliberating on
EITF No. 03-O, Whether Mineral Rights Are Tangible or Intangible Assets, and
EITF No. 03-S, Application of FASB Statement No. 142, Goodwill and Other
Intangible Assets, to Oil and Gas Companies. These proposed statements will
determine whether contract-based oil and gas mineral rights are classified as
tangible or intangible assets based on the EITF's interpretation of SFAS No.
141, Business Combinations, and SFAS No. 142. Historically, the Company has
classified all of its contract-based mineral rights within property, plant and
equipment and has generally not identified these amounts separately. If the EITF
determines that these mineral rights should be presented as intangible assets,
the Company would have to reclassify its contract-based oil and gas mineral
rights acquired after June 30, 2001 to intangible assets and make additional
disclosures in accordance with SFAS No. 142. If The Company adopted this change,
approximately $51 million and $87 million of the property, plant and equipment
balance (net of accumulated depreciation, depletion and amortization) related to
proved properties would be reclassified to intangible assets at December 31,
2003 and 2002, respectively. The Company has been amortizing these amounts under
the unit-of-production method and would continue to amortize the mineral rights
under this method. Based on its understanding of the scope of the EITF
deliberations, the Company believes the adoption of this potential decision
would have no material effect on its results of operations.

3. OFFSHORE PROPERTY TRANSACTIONS

In March 2003, ERT acquired additional interests from Exxon/Mobil ranging
from 45% to 84%, in four fields acquired in 2002, enabling ERT to take over as
operator of one field. ERT paid $858,000 in cash and assumed Exxon/Mobil's
pro-rata share of the abandonment obligation for the acquired interests.

In August 2002, ERT, a wholly owned subsidiary of Cal Dive International,
Inc., acquired the 74.8% working interest of Shell Exploration & Production
Company in the South Marsh Island 130 (SMI 130) field ("Shell acquisition"). ERT
paid $10.3 million in cash and assumed Shell's pro-rata share of the related
decommissioning liability. SMI 130 consists of two blocks, located in
approximately 215 feet of water, with approximately 155 wells on five 8-pile
platforms.

In August 2002, ERT also completed the purchase of seven Gulf of Mexico
fields from Amerada Hess (including its 25% ownership position in SMI 130) for
$9.3 million in cash and assumption of Amerada Hess's pro-rata share of the
related decommissioning liability. As a result, ERT took over as operator with
an effective 100% working interest in that field.

In June 2002, ERT acquired a package of offshore properties from Williams
Exploration and Production. ERT paid $4.9 million and assumed the pro-rata share
of the abandonment obligation for the acquired interests. The blocks purchased
represent an average 30% net working interest in 26 Gulf of Mexico leases.

During the second quarter of 2003, the Company completed purchase price
allocations relating to the Shell acquisition as well as Amerada Hess' interest
in SMI 130 and six other fields, and the June 2002 acquisition of a package of
properties from Williams Exploration and Production. The allocations were based
on settlement agreements as well as additional information obtained relating to
certain asset retirement obligation estimates. The result was a net decrease of
$1.6 million in property and equipment and had no statement of operations
impact.

In April 2002, ERT acquired a 100% interest in East Cameron Block 374,
including existing wells, equipment and improvements. Terms included a cash
payment of approximately $3 million to reimburse the owners for the
inception-to-date cost of the subsea wellhead and umbilical, and an overriding
royalty interest in future production. Cal Dive completed the temporarily
abandoned number one well and performed a subsea tie-back to a host platform.
The cost of completion and tie-back was approximately $7 million, with first
production occurring in August 2002.
58

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As a result of 2002 offshore property acquisitions, ERT assumed net
abandonment liabilities estimated at approximately $63.6 million.

ERT production activities are regulated by the federal government and
require significant third-party involvement, such as refinery processing and
pipeline transportation. The Company records revenue from its offshore
properties net of royalties paid to the Minerals Management Service (MMS).
Royalty fees paid totaled approximately $16.4 million, $9.2 million and $15.2
million for the years ended December 31, 2003, 2002, 2001 respectively. In
accordance with federal regulations that require operators in the Gulf of Mexico
to post an area wide bond of $3 million, the MMS has allowed the Company to
fulfill such bonding requirements through an insurance policy.

During each of the past three years, ERT has sold its interests in certain
fields as well as the platforms and a pipeline. An ERT operating policy provides
for the sale of assets when the expected future revenue stream can be
accelerated in a single transaction. The net result of these sales had no impact
for the years ended December 31, 2003 and 2002 and added two cents to diluted
earnings per common share for the year ended December 31, 2001. These sales were
structured as Section 1031 "Like Kind" exchanges for tax purposes. Accordingly,
the cash received was restricted to use for subsequent acquisitions of
additional oil and gas properties.

4. RELATED PARTY TRANSACTIONS

In April 2000, ERT acquired a 20% working interest in Gunnison, a Deepwater
Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corp. Consistent with CDI's
philosophy of avoiding exploratory risk, financing for the exploratory costs of
approximately $20 million was provided by an investment partnership (OKCD
Investments, Ltd. or "OKCD"), the investors of which include current and former
CDI senior management, in exchange for a revenue interest that is an overriding
royalty interest of 25% of CDI's 20% working interest. CDI provided no
guarantees to the investment partnership. The Board of Directors established
three criteria to determine a commercial discovery and the commitment of Cal
Dive funds: 75 million barrels (gross) of reserves, estimated development costs
of $500 million consistent with 75 MBOE, and a CDI estimated shareholder return
of no less than 12%. Kerr-McGee, the operator, drilled several exploration wells
and sidetracks in 3,200 feet of water at Garden Banks 667, 668 and 669 (the
Gunnison prospect) and encountered significant potential reserves resulting in
the three criteria being achieved during 2001. The exploratory phase was
expanded to ensure field delineation resulting in the investment partnership,
which assumed the exploratory risk, funding approximately $20 million of
exploratory drilling costs. With the sanctioning of a commercial discovery, the
Company funded ongoing development and production costs. Cal Dive's share of
such project development costs is estimated in a range of $110 million to $115
million ($104 million of which had been incurred by December 31, 2003) with over
half of that for construction of the spar. The Company's Chief Executive
Officer, as a Class A limited partner of OKCD, personally owns approximately 57%
of the partnership. Other executive officers of the Company own approximately 6%
combined of the partnership. OKCD has also awarded Class B limited partnership
interests to key CDI employees. See footnote 8 for discussion of the financing
related to the spar construction. Production began in December 2003.

During the fourth quarter of 2000 another investment partnership composed
of Company management and industry sources funded the drilling of a deep
exploratory well at ERT's Vermilion 201 field. Effective January 1, 2001, ERT
acquired approximately 55% of this investment partnership's interest in the
reserves discovered for $2.5 million.

As part of the process of obtaining funding for the exploratory costs of
the above projects, several outside third parties were solicited. Management
believes that the structure of these transactions was both consistent with the
guidelines and at least as favorable to the Company and ERT as could have been
obtained from the third parties.

59

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

During 2003 and 2002, the Company was paid fees of $2,238,000 and $200,000,
respectively, by Ocean Energy, Inc. ("Ocean"), an oil and gas industry customer
of marine contracting services. A member of the Company's board of directors was
a member of senior management of Ocean.

5. ACQUISITION OF BUSINESSES

CANYON OFFSHORE, INC.

In January 2002, CDI purchased Canyon, a supplier of remotely operated
vehicles (ROVs) and robotics to the offshore construction and telecommunications
industries. CDI purchased Canyon for cash of $52.8 million, the assumption of
$9.0 million of Canyon debt (offset by $3.1 million of cash acquired), 181,000
shares of CDI common stock valued at $4.3 million (143,000 shares of which we
purchased as treasury shares during the fourth quarter of 2001) and a commitment
to purchase the redeemable stock in Canyon at a price to be determined by
Canyon's performance during the years 2002 through 2004 from continuing
employees at a minimum purchase price of $13.53 per share (or $7.5 million). The
Company also agreed to make future payments relating to the tax impact on the
date of redemption, whether employment continued or not. As they are employees,
any share price paid in excess of the $13.53 per share will be recorded as
compensation expense. These remaining shares have been classified as redeemable
stock in subsidiary (debt beginning in the third quarter of 2003 -- see
footnotes 2 and 8) in the accompanying balance sheet and will be adjusted to
their estimated redemption value at each reporting period based on Canyon's
performance. The acquisition was accounted for as a purchase with the
acquisition price allocated to the assets acquired and liabilities assumed based
upon their estimated fair values, with the excess being recorded as goodwill.
The allocation of the $70.5 million purchase price was as follows: ROVs and
equipment ($22.9 million); net working capital assumed ($4.0 million) and
goodwill ($43.6 million). The results of Canyon are included in the accompanying
statements of operations since the date of the purchase, January 2, 2002. In
April 2003, the Company purchased approximately one-third of the redeemable
shares at the minimum purchase price of $13.53 per share. Consideration included
approximately $400,000 of contingent consideration relating to tax gross-up
payments paid to the Canyon employees in accordance with the purchase agreement.
This amount was recorded as goodwill in the second quarter of 2003. As of
December 31, 2003, goodwill related to the Canyon acquisition was approximately
$44.7 million.

WELL OPS (U.K.) LIMITED

In July 2002, CDI purchased the subsea well operations business unit of CSO
Ltd., a wholly owned subsidiary of Technip-Coflexip, for approximately $72.0
million ($68.6 million cash and $3.4 million deferred tax liability assumption).
Well Ops (U.K.) Limited performs life of field well operations and marine
construction tasks primarily in the North Sea. The assets purchased include the
Seawell (a 368-foot DPDSV capable of supporting manned diving, ROVs and well
operations). The acquisition was accounted for as a business purchase with the
acquisition price allocated to the assets acquired and liabilities assumed based
upon their estimated fair values, with the excess being recorded as goodwill.
During the fourth quarter of 2002, the Company completed its purchase price
allocation, including obtaining an appraisal of the Seawell, resulting in $50
million allocated to this vessel, $1.5 million allocated to patented technology
(to be amortized over 20 years) and goodwill of approximately $20.6 million as
of December 31, 2002 ($22.2 million as of December 31, 2003). The results of
Well Ops (U.K.) are included in the accompanying statements of operations since
the date of the purchase, July 1, 2002.

6. INVESTMENT IN PRODUCTION FACILITIES -- DEEPWATER GATEWAY, L.L.C.

In June 2002, CDI, along with GulfTerra Energy Partners L.P., ("GulfTerra")
formed Deepwater Gateway, L.L.C. (a 50/50 venture) to design, construct,
install, own and operate a tension leg platform ("TLP") production hub primarily
for Anadarko Petroleum Corporation's Marco Polo field discovery in the

60

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Deepwater Gulf of Mexico. CDI's share of the construction costs is estimated to
be approximately $123 million. In August 2002 the Company, along with GulfTerra,
completed a non-recourse project financing for this venture, terms of which
include a minimum CDI equity investment of $33 million, all of which had been
paid as of December 31, 2003. This is recorded as Investment in Production
Facilities -- Deepwater Gateway, L.L.C. in the accompanying consolidated balance
sheet. Terms of the financing also require CDI to guarantee a balloon payment
due at the end of the financing term in 2008 (estimated to be $22.5 million).
The Company has not recorded any liability for this guarantee as management
believes it is unlikely the Company will be required to pay the balloon payment.

7. ACCRUED LIABILITIES

Accrued liabilities consisted of the following as of December 31, 2003 and
2002 (in thousands):

8. LONG-TERM DEBT

At December 31, 2003, $139.4 million was outstanding on the Company's
long-term financing for construction of the Q4000. This U.S. Government
guaranteed financing is pursuant to Title XI of the Merchant Marine Act of 1936
which is administered by the Maritime Administration ("MARAD Debt"). The MARAD
Debt is payable in equal semi-annual installments beginning in August 2002 and
maturing 25 years from such date. It is collateralized by the Q4000, with CDI
guaranteeing 50% of the debt, and bears interest at a rate which currently
floats at a rate approximating AAA Commercial Paper yields plus 20 basis points
(approximately 1.33% as of December 31, 2003). For a period up to ten years from
delivery of the vessel in April 2002, CDI has the ability to lock in a fixed
rate. In accordance with the MARAD Debt agreements, CDI is required to comply
with certain covenants and restrictions, including the maintenance of minimum
net worth, working capital and debt-to-equity requirements. As of December 31,
2003 the Company was in compliance with these covenants.

The Company has a $70 million revolving credit facility ("Revolver") due in
2005. This facility is collateralized by accounts receivable and certain of the
Company's Marine Contracting vessels, bears interest at LIBOR plus 125-250 basis
points depending on CDI leverage ratios (approximately 3.0% as of December 31,
2003) and, among other restrictions, includes three financial covenants (cash
flow leverage, minimum interest coverage and fixed charge coverage). As of
December 31, 2003, the Company had drawn $30.2 million under the Revolver and
was in compliance with these covenants.

The Company has a $35 million term loan facility which was obtained to
assist CDI in funding its portion of the construction costs of the spar for the
Gunnison field. The loan will be payable in quarterly installments of $1.75
million for three years after delivery of the spar (which was December 2003)
with the remaining $15.75 million due at the end of the three years (2006). The
facility bears interest at LIBOR plus 225-300 basis points depending on CDI
leverage ratios (approximately 3.6% as of December 31, 2003) and includes, among
other restrictions, three financial covenants (cash flow leverage, minimum
interest coverage

61

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and debt to total book capitalization). The Company was in compliance with these
covenants as of December 31, 2003.

In August 2003, Canyon Offshore, Ltd. (a U.K. subsidiary -- "COL"), with a
parent guarantee from CDI, completed a capital lease with a bank refinancing the
construction costs of a newbuild 750 horsepower trenching unit and a ROV. COL
received proceeds of $12 million for the assets and agreed to pay the bank sixty
monthly installment payments of $217,174 (resulting in an implicit interest rate
of 3.29%). No gain or loss resulted from this transaction. COL has an option to
purchase the assets at the end of the lease term for $1. The proceeds were used
to reduce the Company's Revolver, which had initially funded the construction
costs of the assets. This transaction has been accounted for as a capital lease
($11.1 million at December 31, 2003) under SFAS No. 13, Accounting for Leases,
with the present value of the lease obligation (and corresponding asset)
reflected on the Company's consolidated balance sheet beginning in the third
quarter of 2003.

The Company incurred interest expense of $2.6 million, $2.3 million and
$100,000 for the years ended December 31, 2003, 2002, and 2001, respectively.

Scheduled maturities of Long-term Debt outstanding as of December 31, 2003
were as follows (in thousands):

9. INCOME TAXES

CDI and its subsidiaries, including acquired companies from their
respective dates of acquisition, file a consolidated U.S. federal income tax
return. The Company conducts its international operations in a number of
locations that have varying laws and regulations with regard to taxes.
Management believes that adequate provisions have been made for all taxes that
will ultimately be payable. Income taxes have been provided based on the US
statutory rate of 35 percent adjusted for items which are allowed as deductions
for federal

62

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

income tax reporting purposes, but not for book purposes. The primary
differences between the statutory rate and the Company's effective rate are as
follows:

Components of the provision for income taxes reflected in the statements of
operations consist of the following (in thousands):

Deferred income taxes result from the effect of transactions that are
recognized in different periods for financial and tax reporting purposes. The
nature of these differences and the income tax effect of each as of December 31,
2003 and 2002, is as follows (in thousands):

The Company effectively paid no federal income taxes in 2003, 2002 and 2001
due primarily to the deduction of Q4000 construction costs as research and
development for federal tax purposes. The Company paid $1.8 million of federal
income taxes during 2000, but the amount was refunded in January 2001 upon
completing its research and development analysis and filing for the refund. In
addition, the Company filed

63

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

amended tax returns for 1998 and 1999, deducting such costs, resulting in
refunds of $8.2 million which were collected in January 2001.

At December 31, 2003, the Company had $130.6 million of net operating
losses. The use of these net operating losses is subject to limitations imposed
by the Internal Revenue Code and is also restricted to the taxable income of the
subsidiaries generating the losses. Loss carryforwards, if not utilized, will
expire at various dates from 2019 through 2022.

The Internal Revenue Service ("IRS") is in the process of examining the
Company's income tax returns for years 2001 and 2002, and the 2001
pre-acquisition income tax return for Canyon Offshore, Inc. The Company believes
the ultimate resolution of these audits will not have a material adverse effect
on its financial condition, liquidity or results of operations.

10. CONVERTIBLE PREFERRED STOCK

On January 8, 2003, CDI completed the private placement of $25 million of a
newly designated class of cumulative convertible preferred stock (Series A-1
Cumulative Convertible Preferred Stock, par value $0.01 per share) that is
convertible into 833,334 shares of Cal Dive common stock at $30 per share. The
preferred stock was issued to a private investment firm. The preferred
stockholder has the right to purchase as much as $30 million in additional
preferred stock for a period of two years beginning in July 2003. The conversion
price of the additional preferred stock will equal 125% of the then prevailing
market price of Cal Dive common stock, subject to a minimum conversion price of
$30 per common share.

The preferred stock has a minimum annual dividend rate of 4%, or LIBOR plus
150 basis points if greater, payable quarterly in cash or common shares at Cal
Dive's option. CDI paid the first, second, third and fourth quarter 2003
dividends on the last day of the respective quarters in cash. After the second
anniversary, the holder may redeem the value of its original investment in the
preferred shares to be settled in common stock at the then prevailing market
price or cash at the discretion of the Company. In the event the Company is
unable to deliver registered common shares, CDI could be required to redeem in
cash. Under certain conditions (the Company's stock price falling below $7.35
per share or the occurrence of a restatement in the Company's earnings), the
holder could redeem its investment prior to the second anniversary.

The proceeds received from the sale of this stock, net of transaction
costs, have been classified outside of shareholders' equity on the balance sheet
below total liabilities. The transaction costs have been deferred and are being
accreted through the statement of operations over two years. Prior to the
conversion, common shares issuable will be assessed for inclusion in the
weighted average shares outstanding for the Company's diluted earnings per share
using the if converted method based on the Company's common share price at the
beginning of the applicable period.

11. COMMITMENTS AND CONTINGENCIES

LEASE COMMITMENTS

The Company leases several facilities, ROVs and a vessel under
noncancelable operating leases, with the more significant leases expiring in the
years 2004 and 2005. Future minimum rentals under these leases are $12.0 million
at December 31, 2003 with $8.2 million due in 2004, $2.9 million in 2005,
$280,000 in 2006, $279,000 in 2007, $99,000 in 2008 and $288,000 thereafter.
Total rental expense under these operating leases was $8.1 million, $6.9 million
and $779,000 for the years ended December 31, 2003, 2002 and 2001, respectively.

64

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INSURANCE

The Company carries Hull and Increased Value insurance which provides
coverage for physical damage to an agreed amount for each vessel. The
deductibles are based on the value of the vessel with a maximum deductible of
$500,000 on the Q4000. Other vessels carry deductibles between $250,000 and
$350,000. The Company also carries Protection and Indemnity insurance which
covers liabilities arising from the operation of the vessel and General
Liability insurance which covers liabilities arising from construction
operations. The deductible on both the P&I and General Liability is $100,000 per
occurrence. Onshore employees are covered by Workers' Compensation. Offshore
employees, including divers and tenders and marine crews, are covered by
Maritime Employers Liability insurance policy which covers Jones Act exposures
and includes a deductible of $100,000 per occurrence plus a $1 million annual
aggregate. In addition to the liability policies named above, the Company
carries various layers of Umbrella Liability for total limits of $200,000,000
excess of primary limits. The Company's self insured retention on its medical
and health benefits program for employees is $100,000 per claim.

The Company incurs workers' compensation claims in the normal course of
business, which management believes are covered by insurance. The Company, its
insurers and legal counsel analyze each claim for potential exposure and
estimate the ultimate liability of each claim. Amounts accrued and receivable
from insurance companies, above the applicable deductible limits, are reflected
in other current assets in the consolidated balance sheet. Such amounts were
$3.3 million and $5.5 million as of December 31, 2003 and 2002, respectively.
See related accrued liabilities at footnote 7. The Company has not incurred any
significant losses as a result of claims denied by its insurance carriers.

LITIGATION AND CLAIMS

The Company is involved in various routine legal proceedings, primarily
involving claims for personal injury under the General Maritime Laws of the
United States and the Jones Act as a result of alleged negligence. In addition,
the Company from time to time incur other claims, such as contract disputes, in
the normal course of business. In that regard, in 1998, one of the Company's
subsidiaries entered into a subcontract with Seacore Marine Contractors Limited
("Seacore") to provide the Sea Sorceress to a Coflexip subsidiary in Canada
("Coflexip"). Due to difficulties with respect to the sea states and soil
conditions the contract was terminated and an arbitration to recover damages was
commenced. A preliminary liability finding has been made by the arbitrator
against Seacore and in favor of the Coflexip subsidiary. The Company was not a
party to this arbitration proceeding. Seacore and Coflexip settled this matter
prior to the conclusion of the arbitration proceeding with Seacore paying
Coflexip $6.95 million CDN. Seacore has initiated an arbitration proceeding
against Cal Dive Offshore Ltd. ("CDO"), a subsidiary of Cal Dive, seeking
contribution of one-half of this amount. Because only one of the grounds in the
preliminary findings by the arbitrator is applicable to CDO, and because CDO
holds substantial counterclaims against Seacore, it is anticipated that the
Company's subsidiary's exposure, if any, should be less than $500,000.

During 2002, the Company engaged in a large construction project and in
late September of that year, supports engineered by a subcontractor failed
resulting in over a month of downtime for two of CDI's vessels. Management
believes that under the terms of the contract the Company is entitled to
indemnification for the contractual stand-by rate for the vessels during their
downtime (the indemnification claim). The customer has disputed these invoices
along with certain other change orders. Of the amounts billed by CDI for this
project, $9.6 million had not been collected as of December 31, 2003. The
Company has initiated arbitration proceedings, in accordance with the terms of
the contract, to resolve this dispute.

Although the above discussed matters have the potential of significant
additional liability, the Company believes that the outcome of all such matters
and proceedings will not have a material adverse effect on its consolidated
financial position, results of operations or cash flows.

65

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

12. EMPLOYEE BENEFIT PLANS

DEFINED CONTRIBUTION PLAN

The Company sponsors a defined contribution 401(k) retirement plan covering
substantially all of its employees. The Company's contributions are in the form
of cash and are determined annually as 50 percent of each employee's
contribution up to 5 percent of the employee's salary. The Company's costs
related to this plan totaled $785,000, $811,000 and $595,000 for the years ended
December 31, 2003, 2002 and 2001, respectively.

STOCK-BASED COMPENSATION PLANS

During 2000, the Board of Directors approved a "Stock Option in Lieu of
Salary Program" for the Company's Chief Executive Officer. Under the terms of
the program, the participant may annually elect to receive non-qualified stock
options (with an exercise price equal to the closing stock price on the date of
grant) in lieu of cash compensation with respect to his base salary and any
bonus earned under the annual incentive compensation program. The number of
options granted is determined utilizing the Black-Scholes valuation model as of
the date of grant with a risk premium included. The participant made such
election for 2002 and 2001 resulting in a total of 105,000 and 180,000 options
being granted during 2002 and 2001, respectively (which included bonuses earned
under the annual incentive compensation program in 2001 and 2000).

During 1995, the Board of Directors and shareholders approved the 1995
Long-Term Incentive Plan, as amended (the Incentive Plan). Under the Incentive
Plan, a maximum of 10% of the total shares of Common Stock issued and
outstanding may be granted to key executives and selected employees who are
likely to make a significant positive impact on the reported net income of the
Company as well as non-employee members of the Board of Directors. The Incentive
Plan is administered by a committee which determines, subject to approval of the
Compensation Committee of the Board of Directors, the type of award to be made
to each participant and sets forth in the related award agreement the terms,
conditions and limitations applicable to each award. The committee may grant
stock options, stock appreciation rights, or stock and cash awards. Options
granted to employees under the Incentive Plan vest 20% per year for a five year
period or 33% per year for a three year period, have a maximum exercise life of
three, five or ten years and, subject to certain exceptions, are not
transferable.

Effective May 12, 1998, the Company adopted a qualified, non-compensatory
Employee Stock Purchase Plan ("ESPP"), which allows employees to acquire shares
of common stock through payroll deductions over a six month period. The purchase
price is equal to 85 percent of the fair market value of the common stock on
either the first or last day of the subscription period, whichever is lower.
Purchases under the plan are limited to 10 percent of an employee's base salary.
Under this plan 52,572, 44,158 and 38,849 shares of common stock were purchased
in the open market at a weighted average share price of $21.74, $21.86 and
$22.22 during 2003, 2002 and 2001, respectively.

All of the options outstanding at December 31, 2003, have exercise prices
as follows: 108,000 shares at $17.14, 107,060 at $18.06, 129,000 shares at
$19.63, 205,000 shares at $21.38, 270,667 shares at $21.83, 260,419 shares at
$21.88, 120,000 shares at $24.00, 80,000 shares at $26.75 and 442,956 shares
ranging from $7.75 to $23.72 and a weighted average remaining contractual life
of 6.37 years.

66

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Options outstanding are as follows:

13. SHAREHOLDERS' EQUITY

The Company's amended and restated Articles of Incorporation provide for
authorized Common Stock of 120,000,000 shares with no par value per share and
5,000,000 shares of preferred stock, $0.01 par value per share, in one or more
series.

In May 2002, CDI sold 3.4 million shares of primary common stock for $23.16
per share, along with 517,000 additional shares to cover over-allotments.

During the fourth quarter of 2001, CDI purchased 143,000 shares of its
common stock for $2.6 million.

14. BUSINESS SEGMENT INFORMATION (IN THOUSANDS)

The following summarizes certain financial data by business segment:

67

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

During the year ended December 31, 2003, the Company derived approximately
$48.4 million of its revenues from the U.K. sector utilizing approximately $110
million of its total assets in this region. Additionally, $33.0 million of
revenues were derived from the Latin America sector during the year ended
December 31, 2003. The majority of the remaining revenues were generated in the
U.S. Gulf of Mexico.

15. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

The following information regarding the Company's oil and gas producing
activities is presented pursuant to SFAS No. 69, Disclosures About Oil and Gas
Producing Activities (in thousands).

CAPITALIZED COSTS

Aggregate amounts of capitalized costs relating to the Company's oil and
gas producing activities and the aggregate amount of related accumulated
depletion, depreciation and amortization as of the dates indicated are presented
below. The Company has no capitalized costs related to unproved properties.

Included in capitalized costs proved developed properties being amortized
is the Company's estimate of its proportionate share of decommissioning
liabilities assumed relating to these properties which are also reflected as
decommissioning liabilities in the accompanying consolidated balance sheets at
fair value on a discounted basis.

68

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

The following table reflects the costs incurred in oil and gas property
acquisition and development activities, including estimated decommissioning
liabilities assumed, during the years indicated:

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES

Proved oil and gas reserve quantities are based on estimates prepared by
Company engineers in accordance with guidelines established by the U.S.
Securities and Exchange Commission. The Company's estimates of reserves at
December 31, 2003, have been audited by Huddleston & Co., independent petroleum
engineers. All of the Company's reserves are located in the United States.
Proved reserves cannot be measured exactly because the estimation of reserves
involves numerous judgmental determinations. Accordingly, reserve estimates must
be continually revised as a result of new information obtained from drilling and
production history, new geological and geophysical data and changes in economic
conditions.

69

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2001, 6,829,000 Bbls of oil and 35,525,000 Mcf of gas
were undeveloped, all of which is attributable to Gunnison. As of December 31,
2002, 6,375,000 Bbls of oil and 51,807,000 Mcf of gas were undeveloped, 82% of
which is attributable to Gunnison. As of December 31, 2003, 7,608,000 Bbls of
oil and 28,888,000 Mcf of gas were undeveloped, 72% of which is attributable to
Gunnison.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES

The following table reflects the standardized measure of discounted future
net cash flows relating to the Company's interest in proved oil and gas reserves
as of December 31:

70

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

Principal changes in the standardized measure of discounted future net cash
flows attributable to the Company's proved oil and gas reserves are as follows:

16. REVENUE ALLOWANCE ON GROSS AMOUNTS BILLED

The following table sets forth the activity in the Company's Revenue
Allowance on Gross Amounts Billed for each of the three years in the period
ended December 31, 2003 (in thousands):

See Note 2 for a detailed discussion regarding the Company's accounting
policy on the Revenue Allowance on Gross Amounts Billed and Note 11 for a
discussion of a large construction project in 2002.

71

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

17. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The offshore marine construction industry in the Gulf of Mexico is highly
seasonal as a result of weather conditions and the timing of capital
expenditures by the oil and gas companies. Historically, a substantial portion
of the Company's services has been performed during the summer and fall months.
As a result, historically a disproportionate portion of the Company's revenues
and net income is earned during such period. The following is a summary of
consolidated quarterly financial information for 2003 and 2002.

72

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

The Company's management, with the participation of the Company's principal
executive officer (CEO) and principal financial officer (CFO), evaluated the
effectiveness of the Company's disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of
1934, as amended (the "Exchange Act")) as of the end of the fiscal year ended
December 31, 2003. Based on this evaluation, the CEO and CFO have concluded that
the Company's disclosure controls and procedures were effective as of the end of
the fiscal year ended December 31, 2003 to ensure that information that is
required to be disclosed by the Company in the reports it files or submits under
the Exchange Act is recorded, processed, summarized and reported, within the
time periods specified in the SEC's rules and forms. There were no changes in
the Company's internal control over financial reporting that occurred during the
fiscal quarter ended December 31, 2003 that have materially affected, or are
reasonably likely to materially affect, the Company's internal control over
financial reporting.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Except as set forth below, the information required by this Item is
incorporated by reference to the Company's definitive Proxy Statement to be
filed pursuant to Regulation 14A under the Securities Act of 1934 in connection
with the Company's 2004 Annual Meeting of Shareholders. See also "Executive
Officers of the Registrant" appearing in Part I of this Report.

CODE OF ETHICS

The Company has adopted a Code of Business Conduct and Ethics for all
directors, officers and employees as well as a Code of Ethics for Chief
Executive Officer and Senior Financial Officers specific to those officers.
Copies of these documents are available at the Company's Website www.caldive.com
under Corporate Governance. Interested parties may also request a free copy of
these documents from:

Cal Dive International, Inc.
ATTN: Corporate Secretary
400 N. Sam Houston Parkway E., Suite 400
Houston, Texas 77060

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 2004 Annual
Meeting of Shareholders.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 2004 Annual
Meeting of Shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 2004 Annual
Meeting of Shareholders.

73

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 2004 Annual
Meeting of Shareholders.

PART IV

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

(1) Financial Statements

The following financial statements included on pages 42 through 72 in this
Annual Report are for the fiscal year ended December 31, 2003.

Report of Independent Auditors
Report of Independent Public Accountants
Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statements of Operations for the Years Ended December 31,
2003, 2002 and 2001
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 2003, 2002 and 2001
Consolidated Statements of Cash Flows for the Years Ended December 31,
2003, 2002 and 2001
Notes to Consolidated Financial Statements

All financial statement schedules are omitted because the information is
not required or because the information required is in the financial statements
or notes thereto.

(2) Report on Form 8-K.

Current Report on Form 8-K furnished to the SEC on November 4, 2003 to
report the Company's 2003 third quarter financial results.

(3) Exhibits.

Pursuant to Item 601(b)(4)(iii), the Registrant agrees to forward to the
commission, upon request, a copy of any instrument with respect to long-term
debt not exceeding 10% of the total assets of the Registrant and its
consolidated subsidiaries.

The following exhibits are filed as part of this Annual Report:

- ---------------

* Filed herewith.

76

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.

CAL DIVE INTERNATIONAL, INC.

By: /s/ A. WADE PURSELL
------------------------------------
A. Wade Pursell
Senior Vice President, Chief
Financial Officer

March 12, 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.

77

EXHIBIT INDEX

- ---------------

* Filed herewith.