CAL DIVE INTERNATIONAL INC - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K

COMMISSION FILE NUMBER 0-22739
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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 77060
SUITE 400 (Zip Code)
HOUSTON, TEXAS
(Address of principal executive offices)

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. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [ ]

The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant as of June 30, 2004 was $1,080,978,797 based
on the last reported sales price of the Common Stock on June 30, 2004, as
reported on the NASDAQ/National Market System.

The number of shares of the registrant's Common Stock outstanding as of
March 9, 2005 was 38,698,679.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement for the Annual Meeting of
Shareholders to be held on May 10, 2005, are incorporated by reference into Part
III hereof.
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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 development (including subsea construction
and well operations) and providing oil and gas companies with alternatives to
traditional approaches of equity or production sharing in offshore properties
through our Oil & Gas Production and Production Facilities segments. Operations
in the Production Facilities segment began 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 26 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; a Deepwater
production facility at the Marco Polo field; and a planned facility, the
Independence Hub, to be located in Mississippi Canyon Block 920. 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,
Cal Dive International Limited (formerly known as Well Ops (U.K.) Limited),
engineer, manage and conduct well construction,

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intervention and decommissioning operations in water depths from 200 to 10,000
feet in, the Gulf of Mexico and the North Sea, respectively. Cal Dive
International 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 300 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 four 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 (the "mature field strategy"). In 2000,
ERT's reservoir engineering and geophysical expertise enabled us to acquire in
partnership with the operator, Kerr McGee Oil & Gas Corp., a working interest in
Gunnison, a Deepwater Gulf oil and natural gas exploration project, which began
initial production in December 2003. In 2004, ERT continued to successfully
pursue its strategy of acquiring (or partnering in) and developing proved
undeveloped and high probability of success reserves, i.e., leases where
reserves were judged by the current owner to be too marginal to justify
development or they were seeking a partner. Also, in 2004, Cal Dive formed ERT
(U.K.) Limited to explore exporting these strategies to the North Sea.

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
(which began in December 2003), 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, L.L.C., 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 (which began producing in
July 2004). In 2004, we acquired a 20% interest in Independence Hub, LLC, an
affiliate of Enterprise Products Partners L.P. Independence Hub, LLC will own
the "Independence Hub" platform to be located in Mississippi Canyon block 920 in
a water depth of 8,000 feet. Construction is ongoing and is expected to complete
and come online in early 2007. At both Gunnison and Marco Polo, we participated
in field development planning and performed subsea construction work.

Significant financial information relating to the Company's segments for
the last three years is contained in footnote 14 of the Consolidated Financial
Statements included herein, which financial statements are included in Item 8
hereof.

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.

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OUR STRENGTHS

Fleet of DP Vessels. We believe our fleet of DP construction vessels is
one of the 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. We also utilize these capabilities
to develop our own, or partnering interest, in reservoirs.

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 with a single, comprehensive source for addressing current
well operations needs and to engineer for future needs. We also use these
capabilities to maintain, enhance and abandon our own reservoirs.

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. This is
especially true on a broader scale with smaller, economically challenged
reservoirs.

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 suppliers of subsea construction
services on the Gulf of Mexico OCS. We expect the aging infrastructure will
require increasing levels of inspection, maintenance and repair activities, or
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.

Production Facilities. At the Marco Polo field, our 50% ownership in the
production facility allows us to realize a return on investment consisting of
both a fixed monthly demand charge and a volumetric tariff charge. In addition,
we assisted with the installation of the tension leg platform ("TLP") and the
work to develop the surrounding acreage that can be tied back to the platform by
our construction vessels. With the acquisition of a 20% interest in Independence
Hub, LLC, we are in a good position to secure installation and tie-back work
similar to what we achieved at the Marco Polo field. We also own a 20% interest
in the spar at Gunnison. Our long-term goal is that 40% of all of our
construction utilization is provided by ownership of offshore fields and
production facilities. As our track record increases so does the demand for our
model.

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 eight world-class DP vessels, five of which are based in the Gulf of
Mexico. In addition, through Canyon we operate 26 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. In 2004, Canyon purchased an Olympian T1 trencher, which is
currently being upgraded to a "T600" Trencher. Canyon

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represents an integration consistent with our strategy of providing key services
along the critical path of 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
approximately 500 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.

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 twelve
years, we have acquired interests in 90 leases and currently are the operator of
35 of 50 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 our salvage expertise. As an
industry leader in acquiring mature properties, ERT has a significant flow of
potential acquisitions. At December 31, 2004, ERT's total proved reserves were
116.3 Bcfe, including 43.9 Bcfe of proved reserves assigned to our ownership
position in Gunnison.

Expanding Ownership in Production Facilities. Along with Enterprise
Products Partners L.P., Cal Dive owns 50% of the tension leg production platform
installed at the Marco Polo field and 20% of the Independence Hub platform, a
105 foot deep draft, semi-submersible platform. We also own a 20% interest in
the spar at Gunnison. Ownership of these production facilities provides 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 as well as evolved models.

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 prospects where the reserves are judged by
the current owner to be too marginal to justify development. In 2005, ERT will
continue to aggressively pursue its strategy of acquiring reserves and develop
these reserves utilizing Cal Dive's assets. Development of these fields may
require services and a combination of Cal Dive assets to enhance the economics.
Through ERT (U.K.) Limited, we plan to expand the model to the North Sea, and
eventually to the Asian Continent.

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 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

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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 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 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 Superior Energy Services, Inc. (NYSE: SPN).

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.

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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 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 an ROV support vessel the Northern Canyon.

Our subsidiary, Canyon Offshore, Inc., operates ROVs and trenchers 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

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customers with vessel availability and schedule flexibility to meet the
technological challenges of these Deepwater construction developments in the
Gulf and internationally. Our ROVs operate in three regions: the Americas (7),
Europe/West Africa (7) and Asia Pacific (7) regions. In addition to the ROVs,
Canyon also has five trenchers that operate in the Americas (1), Asia Pacific
(1) and the Europe/West Africa (3) regions, including a state of the art "T750"
Super Trencher (Europe/West Africa) and the soon to be completed "T600" Trencher
(Gulf of Mexico).

Utilization of our Deepwater Contracting vessels of 60.6% in 2004 declined
from 2003's utilization of 77.4%; however, utilization of our Well Ops vessels
(the Q4000 and the Seawell) improved to 80.2% in 2004 from 77.5% in 2003. Major
projects for the Deepwater Contracting group in 2003 and 2004 included:

The mission of the Well Ops Group (Well Ops Inc. and Cal Dive International
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; first transit between
wells with intervention riser system deployed; first multiple tree installations
and testing, all of which utilized a semi-submersible DP MSV instead of a
drilling rig; as well as 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 approximately 500 North Sea wells since her
commissioning in 1987, being the only consistent and continuous solution to
light well intervention needs in the region, setting many records and "firsts"
over the last 17 years. One additional advantage is that the Seawell can
undertake saturation diving and construction tasks independently or
simultaneously with the well intervention activities. We believe the Seawell
sets the standard for the industry in subsea well intervention and continues to
redefine the boundaries of the industry. In 2004, the Seawell performed the
first live subsea well interventions from a monohull in the Norwegian Sector,
undertaking work on five Statoil wells during the 2004 Campaign. According to
Statoil, the Seawell operations saved 50% against the cost of a traditional
semi-submersible offshore unit and gained additional value in improving their
recoverable reserves and production rates. Competitive advantages of our vessels
stem from their lower operating costs and the ability to mobilize quickly for
multi-well campaigns of

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work and maximize productive time by performing a broad range of tasks for
intervention, construction, inspection, repair and maintenance. Well Ops Inc.
and Cal Dive International Limited also collaborate with leading downhole
service providers to provide superior, comprehensive solutions to the well
operations challenges faced by our customers.

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 four DP vessels capable of providing
such services, on the OCS. Six 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, has 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 in partnership with the operator,
Kerr-McGee Oil & Gas Corp., a working interest in Gunnison, a Deepwater Gulf oil
and natural gas exploration project, 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.
As an extension of ERT's well exploitation strategy, it is the Company's intent
from time to time

9

to participate in drilling of high probability of success wells which initially
do not possess proven reserves, and thus would be considered exploratory wells.
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 table below sets forth information, as of December 31, 2004, 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, 2004, 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, 2004, we owned an interest in
288 gross (252 net) oil wells and 145 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 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. We
expect significant opportunities as this occurs. At the Marco Polo field, our
50% ownership in the production facility through Deepwater Gateway, L.L.C. 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 assisted with the
installation of the TLP and will work to develop the surrounding acreage that
can be tied back to the platform by our construction vessels. Our 20% interest
in the Independence Hub platform, scheduled for installation in late 2006,
should enable us to repeat the Marco Polo strategy. Through our 20% interest in
the Gunnison field, we also own an interest in the Gunnison 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: 2004 -- Louis Dreyfus
Energy Services (11%) and Shell Trading (US) Company (10%); 2003 -- Shell
Trading (US) Company (10%) and Petrocom Energy Group Ltd. (10%); 2002 -- Horizon
Offshore, Inc. (10%) and BP Trinidad & Tobago LLC (11%). Louis Dreyfus Energy
Services, Shell Trading and Petrocom were purchasers of ERT's oil and gas
production. We estimate in 2004 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 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 2003 and 2004.

GOVERNMENT REGULATION

Many aspects of the offshore marine construction industry are subject to
extensive governmental regulations. We are subject to the jurisdiction of the
U.S. Coast Guard, the U.S. 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, international 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's amendments to
these regulations are subject to judicial review. In 2002, the D.C. Circuit
reversed a 2000 district court decision and upheld a 1997 MMS gas valuation rule
categorically denying allowances for post-production marketing costs such as
long-term storage fees and marketer fees; however, the D.C. Circuit decision
expressly allows firm demand charges to be deducted. Two trade associations had
sought judicial review of the 1997 gas valuation rule and procured a favorable
district court decision; however, the D.C. Circuit decision and denial of
certorari by the Supreme Court ended the litigation in early 2003. In early
2005, the MMS is expected to publish a further revision to its gas valuation
rule. The 2005 gas rule revision will clarify the deductibility of
transportation costs and adopt the 2004 oil valuation rule's cost of capital
approach described below. The revisions are not expected to reflect any major
changes. We cannot predict what effect these changes will have on our operations
but nothing significant is anticipated.

In 2004, the MMS further amended its royalty regulations governing the
valuation of crude oil produced from federal leases. The MMS's 2000 oil
valuation rule had replaced a set of valuation benchmarks based on posted prices
and comparable sales with an indexing system based on spot prices at nearby
market centers. Among other things, the 2000 oil valuation rule (like the 1997
gas valuation rule) also categorically disallowed deductions for post-production
marketing costs. Two industry trade associations sought judicial review of the
2000 oil rule, but voluntarily dismissed their suit after late 2002 negotiations
led the MMS to amend its oil valuation rule further in 2004. The amended rule
retained indexing for valuation but replaced spot prices with NYMEX future
prices, except in the Rocky Mountain Region and California. The 2004 oil
valuation rule also liberalized allowances for non-arm's length transportation
arrangements by increasing the multiplier used for calculating the cost of
capital. While the 2000 oil valuation rule was likely to increase our royalty
obligation somewhat, the 2004 oil valuation rule is likely to attenuate that
increase.

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

12

promulgate revisions to various aspects of the rules and regulations affecting
those segments of the natural gas 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, 2004, we
had approximately 900 employees, nearly 200 of which were salaried personnel. As
of that date, we also utilized approximately 500 non-U.S. citizens to crew our
foreign flag vessels under crewing contracts with C-MAR Services (UK), Ltd. of
Aberdeen, Scotland and Well Ops PTE Limited. None of our employees belong to a
union or are employed pursuant to any collective bargaining agreement or any
similar arrangement. We believe 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, 2004, and copies of the Company's Quarterly Reports on Form 10-Q
for 2004 and 2005 and any Current Reports on Form 8-K for 2004 and 2005, 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 improved somewhat in 2004. We
cannot assure you activity levels will remain the same or increase. 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,
cash flows 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 prudent, including
Jones Act employee coverage, which is the maritime equivalent of workers'
compensation,

16

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 and other Deepwater basins of the world, 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 could be 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, 2004, 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. The Gunnison reserves
constitute approximately 38% of our total proved reserves as of December 31,
2004. This Annual Report contains estimates of our proved oil and gas reserves
and the estimated future net cash flows there from based upon reports for the
year ended December 31, 2003 and 2004, 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 Exchange Commission requirements, we base the estimated

17

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 financial position, cash flows and results of operations.

RESERVE REPLACEMENT MAY NOT OFFSET DEPLETION.

Oil and gas properties are depleting assets. We replace reserves through
acquisitions and exploitation of current properties. If we are unable to acquire
additional properties or if we are unable to find additional reserves through
exploitation of our properties, our future cash flows from oil and gas
operations could decrease.

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. Drilling for oil and gas
involves numerous risks, including the risk that the Company will not encounter
commercially productive oil or gas reservoirs. If certain exploration efforts
are unsuccessful in establishing proved reserves and exploration activities
cease, the amounts accumulated as unproved property costs would be charged
against earnings as impairments.

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.

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

18

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 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 26 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
Q4000in 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 well intervention or 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.

Merlin: Vessel is held for sale at December 31, 2004.

Cal Dive Barge I: Vessel expected to be retired in 2005.

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 21 ROVs and five trencher systems. In
2004, Canyon took delivery of an Olympian T1 trencher that is currently being
upgraded to a "T600" 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.

20

(2) Held for sale at December 31, 2004.

(3) Leased.

(4) Cold stacked.

(5) Expected to be retired in 2005.

(6) Average age of ROV fleet is approximately 4.25 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 on a short-term basis, such as tugboats,
cargo barges, utility boats and dive support vessels. The Q4000 is 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, 2004, 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, 2004, 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, 2004, we owned an interest in
288 gross (252 net) oil wells and 145 gross (91 net) natural gas wells located
in federal and state offshore waters in the Gulf of Mexico.

PRODUCTION FACILITIES

At Gunnison, we own a 20% interest in the Gunnison truss spar facility,
together with the operator Kerr-McGee Oil & Gas Corporation, who owns a 50%
interest, and Nexen, Inc., who owns the remaining 30% interest. The Gunnison
spar, which is moored in 3,150 feet of water and located on Garden Banks Block
668, has daily production capacity of 40,000 barrels of oil and 200 MMCF of gas.
This facility is designed with excess capacity to accommodate production from
satellite prospects in the area.

Through our interest Deepwater Gateway, L.L.C., a 50/50 venture between us
and Enterprise Products Partners L.P., we own a 50% interest in the Marco Polo
TLP, which was installed on Green Canyon Block 608 in 4,300 feet of water.
Deepwater Gateway, L.L.C. was formed to construct, install and own the Marco
Polo TLP in order to process production from Anadarko Petroleum Corporation's
Marco Polo field discovery at Green Canyon Block 608. Anadarko required 50,000
barrels of oil per day and 150 million feet per day of processing capacity for
Marco Polo. The Marco Polo TLP was designed to process 120,000 barrels of oil
per day and 300 million cubic feet per day and payload with space for up to six
subsea tie backs.

We also own a 20% interest in Independence Hub, LLC, an affiliate of
Enterprise Products Partners L.P., that will own the "Independence Hub"
platform, a 105 foot deep draft, semi-submersible platform to be

21

located in Mississippi Canyon block 920 in a water depth of 8,000 feet that will
serve as a regional hub for natural gas production from multiple ultra-deepwater
fields in the previously untapped eastern Gulf of Mexico. Installation of the
platform is scheduled for late 2006 and first production is expected in 2007.

FACILITIES

Our corporate headquarters are located at 400 N. Sam Houston Parkway E.,
Suite 400, Houston, Texas. Our primary subsea and marine services operations are
based in Morgan City, Louisiana. We own the Aberdeen, Scotland facility. All of
our other facilities are leased.

PROPERTIES AND FACILITIES SUMMARY

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 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 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

22

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
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 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 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,
approximately $6.8 million had not been collected as of December 31, 2004. This
matter settled in March 2005 with no material effect on the Company's financial
position or results of operations.

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

None.

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. Mr. Kratz has a Bachelor of Science degree in Biology and Chemistry
from State University of New York.

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 25 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.

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 over 20 years, including nearly 14 years in
his

23

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 Texas State
University -- San Marcos (formerly 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.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, AND RELATED SHAREHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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 9, 2005, the closing sale price of our common stock on the Nasdaq
National Market was $48.80 per share. As of March 9, 2005, there were an
estimated 41 registered shareholders (approximately 4,700 beneficial owners) of
our common stock.

24

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."

ITEM 6. SELECTED FINANCIAL DATA

The financial data presented below for each of the five years ended
December 31, 2004, 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).

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

(1) See discussion at Item 7. Liquidity and Capital Resources -- Financing
Activities.

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

25

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. Oil and
natural gas prices have been at robust levels for the last two years and
offshore drilling activity has increased, but only recently in the Gulf of
Mexico. Our primary leading indicator, the number of offshore mobile rigs
contracted, is currently at approximately 131 rigs employed in the Gulf of
Mexico, slightly higher than year ago levels of 115 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. In the North Sea, the rig count is currently at
59 rigs employed, which compared to 48 during the first quarter of 2004.

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 has increased only modestly
despite higher commodity prices in 2003 and 2004. We cannot assure you that
activity levels will continue to increase. 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.
Historically, we sought to acquire producing oil and gas properties that were
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. In 2000, 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. In 2004, ERT continued to successfully pursue its
strategy of acquiring (or partnering in) and developing proved undeveloped, or
high probability of success reserves, i.e., leases where reserves were judged by
the current owner to be too marginal to justify development or they were seeking
a partner. Each of ERT's oil and gas investments is designed to secure
utilization of CDI construction vessels.

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. We have a 50% interest in the TLP at Marco Polo, which
began production in the second quarter of 2004, and a 20% interest in the
Independence Hub semi-submersible which should be online in early 2007. See
further discussion on the Independence Hub under Liquidity and Capital
Resources -- Investing Activities.

Gunnison reserves constitute approximately 38% of our total proved reserves
as of December 31, 2004. 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

26

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. Further, costs incurred relating to
unsuccessful exploratory wells are expensed in the period the drilling is
determined to be unsuccessful. As an extension of ERT's well exploitation and
PUD strategies, ERT agreed to participate in the drilling of an exploratory well
to be drilled in 2005 that targets reserves in deeper sands, within the same
trapping fault system, of a currently producing well with estimated drilling
costs of approximately $20 million, of which $1.1 million of equipment costs had
been incurred through December 31, 2004. If the drilling is successful, ERT's
share of the development cost is estimated to be an additional $15 million. Our
Marine Contracting assets would participate in this development.

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 normally 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) Derived from information obtained from Platts U.K. and the Baker-Hughes
International Rotary Rig Count for Q1 2002.

(4) Source: Minerals Management Service (2004 and 2003) and Offshore Data
Services (2002); installation and removal of platforms with two or more
piles in the Gulf.

27

(5) 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 those described below. 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.

ACCOUNTING FOR OIL AND GAS PROPERTIES

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.
Costs incurred relating to unsuccessful exploratory wells are expensed in the
period the drilling is determined to be unsuccessful.

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, 2004. 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, 2004 and 2003 related to its Marine
Contracting segment. None of the Company's goodwill was impaired based on the
impairment test performed as of November 1, 2004. The Company will continue to
test its goodwill annually on a consistent measurement 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 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 of recoverability 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. The Company's marine vessels are
assessed on a vessel by vessel basis, while the Company's ROVs are grouped and
assessed by asset class. 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

28

estimate of discounted cash flows. The Company recorded an impairment charge of
$1.9 million (included in Marine Contracting cost of sales in the accompanying
consolidated statement of operations) in December 2004 on certain Marine
Contracting vessels that met the impairment criteria. 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. During the fourth quarter of 2004,
the Company classified a certain Marine Contracting vessel and other property
and equipment intended to be disposed of within a twelve month period as assets
held for sale totaling $5.0 million (included in other current assets in the
accompanying consolidated balance sheet at December 31, 2004). The Company
recorded an impairment charge of $2.0 million (included in Marine Contracting
cost of sales), representing the amount by which their carrying value exceeds
estimated fair value less cost to sell.

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 (based upon discounted cash
flows) 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. 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, 2004, 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.

RECERTIFICATION COSTS AND DEFERRED DRYDOCK CHARGES

The Company's Marine Contracting vessels are required by regulation to be
recertified after certain periods of time. These recertification costs are
incurred while the vessel is in drydock where other routine repairs and
maintenance are performed and, at times, major replacements and improvements are
performed. The Company expenses routine repairs and maintenance as they are
incurred. Recertification costs can be accounted for in one of three ways: (1)
defer and amortize, (2) accrue in advance, or (3) expense as incurred. Companies
in the industry use either the defer and amortize or the expense as incurred
accounting method. The Company defers and amortizes recertification costs over
the length of time in which the recertification is expected to last, which is
generally 30 months. Major replacements and improvements, which extend the
vessel's economic useful life or functional operating capability, are
capitalized and depreciated over the vessel's remaining economic useful life.
Inherent in this process are estimates the Company makes regarding the specific
cost incurred and the period that the incurred cost will benefit.

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. As of December 31, 2004 and 2003, capitalized deferred drydock
charges (included in other assets, net) totaled $10.0 million and $7.3 million,
respectively. During the years ended December 31, 2004, 2003 and 2002, drydock
amortization expense was $4.9 million, $4.1 million and $4.9 million,
respectively.

ACCOUNTING FOR DECOMMISSIONING LIABILITIES

Statement of Financial Accounting Standards ("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

29

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. Decommissioning liabilities were $82.0 million and
$78.4 million at December 31, 2004 and 2003, respectively.

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 other than $15.1 million of restricted cash held in escrow included
in Other Assets, net in the accompanying consolidated balance sheet (see
Liquidity and Capital Resources -- Investing Activities).

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 on 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 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. The Company
recognizes additional contract revenue related to claims when the claim is
probable and legally enforceable. 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, 2004 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

30

than its entitled share, the imbalance is recorded as an asset. As of December
31, 2004 the net imbalance was $3.2 million and was included in Other Current
Assets in the accompanying consolidated balance sheet.

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS

Accounts receivable are stated at the historical carrying amount net of
write-offs and allowance for uncollectible accounts. The Company establishes an
allowance for uncollectible accounts receivable based on historical experience
and any specific customer collection issues that the Company has identified.
Uncollectible accounts receivable are written off when a settlement is reached
for an amount that is less that the outstanding historical balance or when the
Company has determined the balance will not be collected.

FOREIGN CURRENCY

The functional currency for the Company's foreign subsidiary, Cal Dive
International Limited (formerly known as 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 in 2004 and 2003 of
$10.8 million and $5.0 million (net of taxes in 2003), respectively, is included
as accumulated other comprehensive income, as a component of shareholders'
equity. Beginning in 2004, deferred taxes have not been provided on foreign
currency translation adjustments since the Company considers its undistributed
earnings (when applicable) of its non-U.S. subsidiaries to be permanently
reinvested. As a result, cumulative deferred taxes on translation adjustments
totaling approximately $6.5 million were reclassified from noncurrent deferred
income taxes and accumulated other comprehensive income. 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
Europe/West Africa and Asia/ Pacific regions. 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, 2004 and 2003,
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.

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.

31

The fair 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 2004 and 2003, the Company entered into various cash flow hedging
swap and costless collar contracts to stabilize 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 hedge instruments was a net liability of $876,000 and $2.2 million as of
December 31, 2004 and 2003, respectively. For the years ended December 31, 2004
and 2003 the Company recorded unrealized gains of approximately $846,000 and
$1.2 million, net of taxes of $456,000 and $654,000, respectively, in other
comprehensive income, a component of shareholders' equity as these hedges were
highly effective. The balance in the cash flow hedge adjustments account is
recognized in earnings when the hedged item is sold. During 2004 and 2003, the
Company reclassified approximately $11.1 million and $14.6 million,
respectively, of losses from other comprehensive income to Oil and Gas
Production revenues upon the sale of the related oil and gas production.

EQUITY INVESTMENTS

Our equity investments in unconsolidated subsidiaries include our
investments in Deepwater Gateway, L.L.C. and Independence Hub, LLC. We review
our equity investments for impairment and record an adjustment when we believe
the decline in fair value is other than temporary. The fair value of the asset
is measured using quoted market prices or, in the absence of quoted market
prices, fair value is based on an estimate of discounted cash flows. In
determining whether the decline is other than temporary, we consider the
cyclical nature of the industry in which the investment operates, its historical
performance, its performance in relation to its peers and the current economic
environment. We will monitor the fair value of our investments for impairment
and will record an adjustment if we believe a decline is other than temporary.
During 2004 and 2003 no impairment indicators existed.

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. The Company considers the undistributed earnings of
its non-U.S. subsidiaries to be permanently reinvested. At December 31, 2004,
the Company's non-U.S. subsidiaries had an accumulated deficit of $8.9 million
in earnings and profits. These losses are primarily due to timing differences
related to fixed assets. The Company has not provided deferred U.S. income tax
on the losses. 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 our
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 substantially covered by insurance. The
Company, its insurers and legal counsel analyze each claim for potential
exposure and estimate the ultimate liability of each claim.

32

RECENTLY ISSUED ACCOUNTING PRINCIPLES

In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based
Payment ("SFAS No. 123R"), which replaces SFAS No. 123, Accounting for
Stock-Based Compensation, ("SFAS No. 123") and supercedes APB Opinion No. 25,
Accounting for Stock Issued to Employees. SFAS No. 123R requires all share-based
payments to employees, including grants of employee stock options, to be
recognized in the financial statements based on their fair values beginning with
the first interim or annual period after June 15, 2005, with early adoption
encouraged. The pro forma disclosures previously permitted under SFAS No. 123 no
longer will be an alternative to financial statement recognition. The Company is
required to adopt SFAS No. 123R in the third quarter of fiscal 2005, beginning
July 1, 2005. Under SFAS No. 123R, the Company must determine the appropriate
fair value model to be used for valuing share-based payments, the amortization
method for compensation cost and the transition method to be used at date of
adoption. The transition methods include prospective and retroactive adoption
options. Under the retroactive option, prior periods may be restated either as
of the beginning of the year of adoption or for all periods presented. The
prospective method requires that compensation expense be recorded for all
unvested stock options and restricted stock at the beginning of the first
quarter of adoption of SFAS No. 123R, while the retroactive methods would record
compensation expense for all unvested stock options and restricted stock
beginning with the first period restated. The Company has not yet determined the
method of adoption of SFAS No. 123R. The Company is evaluating the requirements
of SFAS No. 123R and expects that the adoption of SFAS No. 123R will not have a
material impact on the Company's consolidated results of operations and earnings
per share.

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary
Assets, an Amendment of APB Opinion No. 29, which is effective for the Company
for asset-exchange transactions beginning July 1, 2005. Under APB 29, assets
received in certain types of nonmonetary exchanges were permitted to be recorded
at the carrying value of the assets that were exchanged (i.e., recorded on a
carryover basis). As amended by SFAS No. 153, assets received in some
circumstances will have to be recorded instead at their fair values. In the
past, the Company has not engaged in a large number of nonmonetary asset
exchanges for significant amounts.

RESULTS OF OPERATIONS

We derive our revenues, earnings and cash flows from three primary business
segments: Marine Contracting, Oil and Gas Production and Production Facilities.
Within Marine Contracting, we operate primarily in the Gulf of Mexico (Gulf),
and recently in the North Sea and Asia/Pacific regions, with services that cover
the lifecycle of an offshore oil or gas field. Our current diversified fleet of
22 vessels and 26 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 began in 2004 with Marco Polo coming online.
Investments in our Production Facilities segment is currently accounted for
under the equity method of accounting. Our customers include major and
independent oil and gas producers, pipeline transmission companies and offshore
engineering and construction firms.

COMPARISON OF YEARS ENDED 2004 AND 2003

Revenues. During the year ended December 31, 2004, the Company's revenues
increased 37% to $543.4 million compared to $396.3 million for the year ended
December 31, 2003. Of the overall $147.1 million increase, $106.0 million was
generated by the Oil and Gas Production segment due to increased oil and gas
production and higher commodity prices. Marine Contracting revenues increased
$41.1 million from $259.0 million for 2003 to $300.1 million for 2004 due
primarily to slightly increased utilization and improved contract pricing for
the Company's Well Ops Group and improved performance from the Company's ROV
division.

33

Oil and Gas Production revenue for the year ended December 31, 2004
increased $106.0 million, or 77%, to $243.3 million from $137.3 million during
2003. Production increased 43% (39.8 Bcfe for the year ended December 31, 2004
compared to 27.9 Bcfe in 2003) primarily as a result of our successful well
exploitation program, bringing a subsea PUD development online late in 2003, and
Gunnison wells coming online throughout 2004 and provided 21% of total
production. The average realized natural gas price of $6.13 per Mcf, net of
hedges in place, during 2004 was 23% higher than the $4.98 per Mcf realized in
2003 while average realized oil prices, net of hedges in place, increased 28% to
$35.34 per barrel compared to $27.63 per barrel realized during 2003.

Gross Profit. Gross profit of $171.9 million for the year ended December
31, 2004 represented an 87% increase compared to the $92.1 million recorded in
the prior year with the Oil and Gas Production segment contributing 87% of the
increase. Marine Contracting gross profit increased to $36.5 million, for the
year ended December 31, 2004, from $26.0 million in the prior year. The increase
was primarily attributable to improved contract pricing for the Company's Well
Ops Group and improved performance from the Company's ROV division, partially
offset by asset impairments on certain Shelf and Deepwater division vessels
totaling $3.9 million for conditions meeting the Company's asset impairment
criteria. Oil and Gas Production gross profit increased $69.3 million, to $135.4
million, due to the aforementioned higher levels of production and commodity
price increases.

Gross margins of 32% in 2004 were 9 points better than the 23% in 2003.
Marine Contracting margins increased 2 points to 12% for the year ended December
31, 2004, from 10% in the prior year, due to the factors noted above. In
addition, margins in the Oil and Gas Production segment increased 8 points to
56% for the year ended December 31, 2004, from 48% in 2003, due primarily to the
higher oil and gas commodity prices.

Selling & Administrative Expenses. Selling and administrative expenses of
$48.9 million for the year ended December 31, 2004 were $13.0 million higher
than the $35.9 million incurred in 2003 due primarily to an increase in the 2004
Marine Contracting compensation program, which is based on certain individual
performance criteria and the Company's profitability, and the ERT incentive
compensation program, which is tied directly to the Oil and Gas Production
segment profitability that was significantly higher in 2004 compared to 2003.
Selling and administrative expenses at 9% of revenues for 2004 matched that of
the prior year.

Equity in Earnings of Production Facilities Investments. Equity in
earnings of the Company's 50% investment in Deepwater Gateway, L.L.C. increased
to $7.9 million in 2004 compared with a loss of $87,000 in 2003. The increase
was attributable to the demand fees which commenced following the March 2004
mechanical completion of the Marco Polo tension leg platform, owned by Deepwater
Gateway, L.L.C., as well as production tariff charges which commenced in the
third quarter of 2004 as Marco Polo began producing.

Other (Income) Expense. The Company reported other expense of $5.3 million
for the year ended December 31, 2004 compared to other expense of $3.4 million
for the year ended December 31, 2003. Net interest expense of $5.6 million in
2004 was higher than the $2.4 million incurred in 2003, due primarily to
$243,000 of capitalized interest in 2004, compared with $3.4 million in 2003,
which related to the Company's investment in Gunnison and construction of the
Marco Polo tension leg platform, both of which were online at different times
during 2004.

Income Taxes. Income taxes increased to $43.0 million for the year ended
December 31, 2004 compared to $19.0 million in 2003, primarily due to increased
profitability. The effective tax rate of 34.2% in 2004 is lower than the 36.1%
effective tax rate for 2003 due to the benefit recognized by the Company for its
research and development credits in the first quarter of 2004 as a result of the
conclusion of the Internal Revenue Service ("IRS") examination of the Company's
income tax returns for 2001 and 2002, and the tax cost or benefit of U.S. and
U.K. branch operations.

Net Income. Net income of $79.9 million for 2004 was $47.1 million greater
than 2003 as a result of the factors described above. Further, convertible
preferred stock dividends and accretion increased from $1.4 million in 2003 to
$2.7 million in 2004 as a result of the Series A-2 Tranche of convertible
preferred stock issued in June 2004 to the existing holder. See Liquidity and
Capital Resources -- Financing Activities.

34

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 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 months 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 36.1% in 2003 compared to 35.0% in 2002 due
primarily to provisions for foreign taxes. The 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.

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

35

administered by the Maritime Administration. We refer to this debt as MARAD
Debt. At December 31, 2004, $136.4 million was outstanding on this debt. In
August 2004 we closed a four year, $150 million revolving credit facility with a
syndicate of banks. This facility was undrawn upon at December 31, 2004. 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. These acquisitions significantly
increased our debt to total book capitalization ratio from 31% at December 31,
2001 to 40% at December 31, 2002. Cash flow from operations, along with the
private placement of convertible preferred stock in January 2003 ($25 million,
or $24.1 million net of transaction costs) and June 2004 ($30 million, or $29.3
million net of transaction costs), have enabled us to reduce this ratio to 22%
as of December 31, 2004, as well as to build $91.1 million of unrestricted cash
as of December 31, 2004.

Operating Activities. Net cash provided by operating activities was $226.8
million during 2004, an increase of $139.4 million over the $87.4 million
generated during 2003 due primarily to an increase in profitability ($48.5
million), a $37.5 million increase in depreciation and amortization (including
the non-cash asset impairment charge in 2004) resulting from the aforementioned
increase in production levels (including the Gunnison wells that began producing
in December 2003). Further an increase in trade payables and accrued liabilities
of $53.1 million due primarily to higher accruals for ERT royalties as a result
of increased production and higher accruals for ERT and Marine Contracting
incentive compensation also contributed to the increase in operating cash flow.
Cash flow from operations was negatively impacted by an increase in other
current assets ($28.3 million) primarily for prepaid insurance and current
deferred taxes.

In March 2004, the Company elected not to renew its alliance with Horizon
Offshore, Inc. As part of the settlement of outstanding trade accounts
receivable with Horizon, the Company obtained exclusive use of a Horizon
spoolbase facility for a period of five years. Utilization of the spoolbase
facility was valued at approximately $2.0 million with the Company offsetting a
corresponding amount of trade accounts receivable in exchange for the
utilization agreement. The value of the spoolbase facility is being amortized
over the five year term of the agreement. Trade receivables from Horizon at
December 31, 2004 and 2003 were approximately $3.3 million and $11.0 million,
respectively.

Net cash provided by operating activities was $87.4 million during 2003, as
compared to $66.9 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.

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 investments in our Production
Facilities. We incurred $82.3 million of capital investments during 2004, $95.4
million during 2003 and $312.8 million in 2002.

We incurred $50.1 million of capital expenditures during 2004 compared to
$93.2 million in 2003. Included in the capital expenditures during 2004 was $5.5
million for the purchase of an intervention riser system, $14.8 million for ERT
well exploitation programs, $19.6 million for further Gunnison field
development, $6.7 million for the purchase of an operations facility in
Aberdeen, Scotland to serve as our UK headquarters and $3.5 million for the
purchase and upgrade of a trencher system for our ROV division.

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.

36

In 2004, we invested $32.2 million in our Production Facilities segment
which consists of our equity method investments in Deepwater Gateway, L.L.C. and
Independence Hub, LLC. In June 2002, CDI, along with Enterprise Products
Partners L.P. ("Enterprise"), formed Deepwater Gateway, L.L.C. (a 50/50 venture
accounted for by CDI under the equity method of accounting) to design,
construct, install, own and operate TLP production hub primarily for Anadarko
Petroleum Corporation's Marco Polo field discovery in the Deepwater Gulf of
Mexico. In August 2002, the Company along with Enterprise, completed a
non-recourse project financing for this venture, terms of which include a
minimum equity investment in Deepwater Gateway, L.L.C. of $33 million, all of
which had been paid as of December 31, 2004, and is recorded as Investments in
Production Facilities in the accompanying consolidated balance sheet. The
Company's investment in Deepwater Gateway, L.L.C. totaled $56.6 million as of
December 31, 2004. Included in the investment account was capitalized interest
and insurance paid by the Company totaling approximately $2.6 million. In June
2004, the Deepwater Gateway, L.L.C. construction loan, excluded from the
Company's long-term debt, was converted to a term loan. The term loan is
collateralized by substantially all of Deepwater Gateway, L.L.C.'s assets and is
non-recourse to the Company except for the balloon payment due at the end of the
term. In the event of default, the Company would be required to pay up to $22.5
million; however, 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 $22.5 million. In December 2004, the Company received its first distribution
from Deepwater Gateway, L.L.C. totaling $7.5 million. The $7.5 million
distribution was recorded as restricted cash (included in other assets, net in
the accompanying consolidated balance sheet) at December 31, 2004 as the Company
is required to escrow distributions from Deepwater Gateway, L.L.C. up to the
first $22.5 million. In accordance with terms of the term loan, Deepwater
Gateway, L.L.C. has the right to repay the principal amount plus any accrued
interest due under its term loan at any time without penalty. Deepwater Gateway,
L.L.C. has decided to extinguish its term loan. The Company and Enterprise will
make equal cash contributions (approximately $72 million each) to Deepwater
Gateway, L.L.C. to fund the repayment. At March 9, 2005, the term loan principal
amount owed by Deepwater Gateway, L.L.C. was $144 million.

In December 2004, CDI acquired a 20% interest (accounted for by CDI under
the equity method of accounting) in Independence Hub, LLC ("Independence"), an
affiliate of Enterprise. Independence will own the "Independence Hub" platform
to be located in Mississippi Canyon block 920 in a water depth of 8,000 feet.
Independence has previously executed agreements with the Atwater Valley
Producers Group of five exploration and production companies for the dedication
and processing of natural gas and condensate production from fields in the
Atwater Valley, DeSoto Canyon and Lloyd Ridge areas of the deepwater Gulf of
Mexico on the Independence Hub platform. As part of that transaction, the
producers have also dedicated future production from a number of undeveloped
blocks in the area for processing. The 105 foot deep draft, semi-submersible
platform will serve as a regional hub for natural gas production from multiple
ultra-deepwater fields in the previously untapped eastern Gulf of Mexico. The
platform, which is estimated to cost approximately $385 million, will be capable
of processing 850 million cubic feet of gas per day. It is designed to process
production from six anchor fields and has excess payload capacity to tie back up
to 10 additional fields. CDI's initial investment of $10.6 million has been paid
as of December 31, 2004, and its total investment in Independence is expected to
be approximately $77 million. Further, CDI is party to a guaranty agreement with
Enterprise to the extent of CDI's ownership in Independence (20% at December 31,
2004). The agreement states, among other things, that CDI and Enterprise
guarantee performance under the Independence Hub Agreement between Independence
and the producers group of exploration and production companies up to $397.5
million, plus applicable attorneys' fees and related expenses. CDI has estimated
the fair value of its share of the guarantee obligation to be immaterial at
December 31, 2004 based upon the remote possibility of payments being made under
the performance guarantee.

In March 2005, ERT acquired a 30% working interest in a proven undeveloped
field in Atwater Valley Block 63 of the deepwater Gulf of Mexico for cash
consideration and assumption of certain decommissioning liabilities. ERT's
expected share of development costs for 2005 through 2007 are approximately $70
million to $100 million.

As of December 31, 2004, the Company had $22.6 million of restricted cash,
included in other assets, net in the accompanying consolidated balance sheet, of
which $15.1 million related to ERT's escrow funds for

37

decommissioning liabilities associated with the SMI 130 field acquisitions in
2002 and $7.5 million related to the Investment in Deepwater Gateway, L.L.C.
discussed previously. Under the purchase agreement, ERT is obligated to escrow
50% of production up to the first $20 million and 37.5% of production on the
remaining balance up to $33 million in total escrow. Once the escrow reaches $10
million, ERT may use the restricted cash for decommissioning the related fields.

In March 2003, ERT acquired additional interests, 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.

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 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 April 2000, ERT acquired a 20% working interest in Gunnison, a Deepwater
Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corp. 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.
Production began in December 2003. Payments to OKCD from ERT totaled $20.3
million in the year ended December 31, 2004. 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.

Financing Activities. We have financed seasonal operating requirements and
capital expenditures with internally generated funds, borrowings under credit
facilities, the sale of equity and project financings. Our largest debt
financing has been the MARAD debt. No draws were made on this facility in 2004
and 2003. The MARAD debt is payable in equal semi-annual installments which
began in August 2002 and matures 25 years from such date. We made two payments
each during 2004 and 2003 totaling $2.9 million and $2.8 million, respectively.
The MARAD Debt is collateralized by the Q4000, with Cal Dive guaranteeing 50% of
the debt,

38

and bears an interest rate which currently floats at a rate approximating AAA
Commercial Paper yields plus 20 basis points (approximately 2.47% as of December
31, 2004). CDI has paid MARAD guarantee fees for this debt which adds
approximately 50 basis points per annum of interest expense. For a period up to
ten years from delivery of the vessel in April 2002, the Company has the ability
to lock in a fixed rate. In accordance with the MARAD Debt 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, 2004, we were in compliance with these
covenants.

The Company had a $70 million revolving credit facility originally due in
February 2005. This facility was collateralized by accounts receivable and
certain of the Company's Marine Contracting vessels. All outstanding borrowings
under the facility were repaid during 2004 and the facility was cancelled and
terminated in August 2004, and replaced by the new $150 million revolving credit
facility described below.

In August 2004, the Company entered into a four year, $150 million
revolving credit facility with a syndicate of banks, with Bank of America, N.A.
as administrative agent and lead arranger. The amount available under the
facility may be increased to $250 million at any time upon the agreement of the
Company and the existing or additional lenders. The new credit facility is
secured by the stock in certain Company subsidiaries and contains a negative
pledge on assets. The new facility bears interest at LIBOR plus 75 -- 175 basis
points depending on Company leverage and contains financial covenants relative
to the Company's level of debt to EBITDA, as defined in the credit facility,
fixed charge coverage and book value of assets coverage. As of December 31,
2004, the Company was in compliance with these covenants and there was no
outstanding balance under this facility.

The Company had 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 was repaid in full in August 2004, and the loan
agreement was subsequently cancelled and terminated.

In connection with borrowings under credit facilities and long-term debt
financings, the Company has paid deferred financing costs totaling $4.6 million,
$208,000 and $1.7 million in the years ended December 31, 2004, 2003 and 2002,
respectively.

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. Subsequently in June
2004, the preferred stockholder exercised its existing right and purchased $30
million in additional cumulative convertible preferred stock (Series A-2
Cumulative Convertible Preferred Stock, par value $0.01 per share). In
accordance with the January 8, 2003 agreement, the $30 million in additional
preferred stock is convertible into 982,029 shares of Cal Dive common stock at
$30.549 per share. In the event the holder of the convertible preferred stock
elects to redeem into Cal Dive common stock and Cal Dive's common stock price is
below the conversion prices, unless the Company has elected to settle in cash,
the holder would receive additional shares above the 833,334 common shares
(Series A-1 tranche) and 982,029 common shares (Series A-2 tranche). The
incremental shares would be treated as a dividend and reduce net income
applicable to common shareholders. The preferred stock has a minimum annual
dividend rate of 4%, subject to adjustment, payable quarterly in cash or common
shares at Cal Dive's option. CDI paid these dividends in 2004 and 2003 on the
last day of the respective quarter in cash. After the second anniversary of the
original issuance, the holder may redeem the value of its original and
additional 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.

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%). 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 revolving credit
facility, which had initially

39

funded the construction costs of the assets. This transaction was accounted for
as a capital lease with the present value of the lease obligation (and
corresponding asset) being reflected on the Company's consolidated balance sheet
beginning in the third quarter of 2003.

In April 2004 and 2003, the Company purchased approximately one-third and
one-third, respectively, of the redeemable stock in Canyon related to the Canyon
purchase (see Investing Activities above and footnote 5 in the accompanying
consolidated financial statements included herein for discussion of the Canyon
acquisition) at the minimum purchase price of $13.53 per share ($2.5 million and
$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.

During 2004, 2003 and 2002, we made payments of $3.6 million, $2.4 million
and $5.2 million separately on capital leases related to Canyon. The only other
financing activity during 2004, 2003 and 2002 involved the exercise of employee
stock options ($11.0 million, $3.6 million and $5.9 million, respectively).

The following table summarizes our contractual cash obligations as of
December 31, 2004 and the scheduled years in which the obligation are
contractually due:

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

(1) Excludes CDI guarantee of payment due in 2009 on term loan related to
Deepwater Gateway, L.L.C. (estimated to be $22.5 million), guarantee of
performance related to the construction of the Independence Hub platform
under Independence Hub, LLC (estimated to be immaterial at December 31,
2004) and unsecured letters of credit outstanding at December 31, 2004
totaling $3.7 million. These letters of credit primarily guarantee various
contract bidding and insurance activities.

(2) In accordance with terms of the term loan, Deepwater Gateway, L.L.C. has the
right to repay the principal amount plus any accrued interest due under its
term loan at any time without penalty. Deepwater Gateway, L.L.C. has decided
to extinguish its term loan. The Company and Enterprise will make equal cash
contributions (approximately $72 million each) to Deepwater Gateway, L.L.C.
to fund the repayment. At March 9, 2005, the term loan principal amount owed
by Deepwater Gateway, L.L.C. was $144 million.

(3) In March 2005, ERT acquired a 30% working interest in a proven undeveloped
field in Atwater Valley Block 63 of the deepwater Gulf of Mexico for cash
consideration and assumption of certain decommissioning liabilities. ERT's
expected share of development costs for 2005 through 2007 are approximately
$70 million to $100 million.

40

(4) As an extension of ERT's well exploitation and PUD strategies, ERT agreed to
participate in the drilling of an exploratory well to be drilled in 2005
that targets reserves in deeper sands, within the same trapping fault
system, of a currently producing well. If the drilling is successful, ERT's
share of the development cost is estimated to be an additional $15 million.
CDI's Marine Contracting assets would participate in this development.

In addition, in connection with our business strategy, we regularly
evaluate acquisition opportunities (including additional vessels as well as
interest in offshore natural gas and oil properties). We believe 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 rates, commodity prices and foreign currency exchange rates.

Interest Rate Risk

Because the majority of the Company's debt at December 31, 2004 was based
on floating rates, changes in interest would, assuming all other things equal,
have a minimal impact on the fair value of the debt instruments, but every 100
basis points move in interest rates would result in approximately $1.4 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 2004 and 2003 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.

As of December 31, 2004, 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 value of these instruments to increase or decrease
inversely to the change in NYMEX prices.

Subsequent to December 31, 2004, the Company entered into additional oil
costless collars for the periods July through December 2005 and October through
December 2005. The July contract covers 20 MBbl per month at a price of $37.00
to $50.50 and the October contract covers 20 MBbl per month at a price of $37.00
to $50.80. The Company also entered into additional natural gas costless collars
for the period July through December 2005. The contracts cover 225,000 MMBtu per
month at a weighted average price of $5.00 to $9.44.

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 Cal Dive International Limited).
The functional currency for Cal Dive International Limited is the applicable
local currency (British Pound). Although the revenues are denominated in the
local currency, the effects of foreign

41

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, 2004
and 2003, respectively, did not have a material effect on reported amounts of
revenues or net income.

Assets and liabilities of Cal Dive International 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 14% of our assets are impacted by changes in foreign currencies in
relation to the U.S. dollar. We recorded gains of $10.8 and $5.0 million (net of
taxes in 2003) to our equity account in the years ended December 31, 2004 and
2003, respectively, to reflect the net impact of the decline of the U.S. dollar
against the British Pound. Beginning in 2004, deferred taxes have not been
provided on foreign currency translation adjustments since the Company considers
its undistributed earnings (when applicable) of its non-U.S. subsidiaries to be
permanently reinvested. As a result, cumulative deferred taxes on translation
adjustments totaling approximately $6.5 million were reclassified from
noncurrent deferred income taxes and accumulated other comprehensive income.

Canyon Offshore, the Company's ROV subsidiary, has operations in the
Europe/West Africa and Asia/ Pacific regions. Canyon conducts the majority of
its operations 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 transaction gain or loss is recognized in the
statements of operations. These amounts for the years ended December 31, 2004
and 2003, respectively, were not material to the Company's results of operations
or cash flows.

42

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

43

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Cal Dive International, Inc., together with its consolidated
subsidiaries (the "Company"), is responsible for establishing and maintaining
adequate internal control over financial reporting. The Company's internal
control over financial reporting is a process designed under the supervision of
the Company's principal executive and principal financial officers to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of the Company's financial statements for external reporting
purposes in accordance with U.S. generally accepted accounting principles.

As of the end of the Company's 2004 fiscal year, management conducted an
assessment of the effectiveness of the Company's internal control over financial
reporting using the criteria set forth in the framework established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this assessment, management
has determined that the Company's internal control over financial reporting as
of December 31, 2004 is effective.

Our internal control over financial reporting includes policies and
procedures that pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect transactions and dispositions of assets of
the Company; provide reasonable assurances that transactions are recorded as
necessary to permit preparation of financial statements in accordance with U.S.
generally accepted accounting principles, and that receipts and expenditures are
being made only in accordance with authorizations of management and the
directors of the Company; and provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use or disposition of the
Company's assets that could have a material effect on our financial statements.

Management's assessment of the effectiveness of the Company's internal
control over financial reporting as of December 31, 2004 has been audited by
Ernst & Young LLP, an independent registered public accounting firm, as stated
in their report appearing on page 46, which expresses an unqualified opinion on
management's assessment and on the effectiveness of Company's internal control
over financial reporting as of December 31, 2004.

44

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2004 and 2003, and the
related consolidated statements of operations, shareholders' equity and cash
flows for each of the three years in the period ended December 31, 2004. 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 the standards of the Public
Company Accounting Oversight Board (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, 2004 and 2003, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 2004, in conformity with U.S.
generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of Cal
Dive International, Inc.'s internal control over financial reporting as of
December 31, 2004, based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated March 11, 2005 expressed an unqualified opinion
thereon.

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" in 2003.

/s/ ERNST & YOUNG LLP

Houston, Texas
March 11, 2005

45

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
INTERNAL CONTROL OVER FINANCIAL REPORTING

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

We have audited management's assessment, included in the accompanying
Management's Report on Internal Control Over Financial Reporting, that Cal Dive
International, Inc. maintained effective internal control over financial
reporting as of December 31, 2004, based on criteria established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). Cal Dive
International, Inc.'s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express an opinion on management's assessment and an opinion on the
effectiveness of the company's internal control over financial reporting based
on our audit.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinion.

A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Cal Dive International, Inc.
maintained effective internal control over financial reporting as of December
31, 2004, is fairly stated, in all material respects, based on the COSO
criteria. Also, in our opinion, Cal Dive International, Inc. maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of Cal Dive International, Inc. as of December 31, 2004 and 2003, and the
related consolidated statements of operations, shareholders' equity and cash
flows for each of the three years in the period ended December 31, 2004 of Cal
Dive International, Inc. and Subsidiaries and our report dated March 11, 2005
expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas
March 11, 2005

46

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2004 AND 2003

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

47

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

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

48

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

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

49

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

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

50

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 three
primary business segments: Marine Contracting, Oil & Gas Production and
Production Facilities. Within its Marine Contracting segment, CDI operates
primarily in the Gulf of Mexico (Gulf), the North Sea and Asia/Pacific regions,
with services that cover the lifecycle of an offshore oil or gas field. CDI's
current diversified fleet of 22 vessels and 26 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 (through its wholly
owned subsidiary Energy Resource Technology, Inc.) as well as production
facilities. Operations in the Production Facilities segment began in 2004 with
Marco Polo coming online. The Production Facilities segment is currently
accounted for under the equity method of accounting and includes the Company's
50% investment in Deepwater Gateway, L.L.C. and its 20% investment in
Independence Hub, LLC. 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. and its 20% interest in Independence Hub,
LLC using the equity method of accounting as the Company does not have voting or
operational control of either entity.

Certain reclassifications were made to previously reported amounts in the
consolidated financial statements and notes thereto to make them consistent with
the current presentation format.

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
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, 2004. The
Company's goodwill impairment test involves a comparison of the fair value of
each of the Company's reporting units with its

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

carrying amount. All of the Company's goodwill as of December 31, 2004 and 2003
related to its Marine Contracting segment. None of the Company's goodwill was
impaired based on the impairment test performed as of November 1, 2004. The
Company will continue to test its goodwill annually on a consistent measurement
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.
Costs incurred relating to unsuccessful exploratory wells are expensed in the
period the drilling is determined to be unsuccessful.

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. The resulting decommissioning liability is reflected on the
face of the balance sheet at fair value on a discounted basis. 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):

The Company capitalized interest totaling $243,000, $3.4 million and $4.4
million during the years ended December 31, 2004, 2003 and 2002, 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 $17.0 million, $14.7 million and $11.5
million for the years ended December 31, 2004, 2003 and 2002, respectively.

For long-lived assets to be held and used, excluding goodwill, the Company
bases its evaluation of recoverability 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. The Company's marine vessels are
assessed on a vessel by vessel basis, while the Company's ROVs are grouped and
assessed by asset class. If an impairment has occurred, the Company recognizes a
loss

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. The Company recorded an impairment charge of $1.9 million (included in
Marine Contracting cost of sales) in December 2004 on certain Marine Contracting
vessels that met the impairment criteria. 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. During the fourth quarter of 2004, the Company
classified a certain Marine Contracting vessel and other property and equipment
intended to be disposed of within a twelve month period as assets held for sale
totaling $5.0 million (included in other current assets at December 31, 2004).
The Company recorded an impairment charge of $2.0 million (included in Marine
Contracting cost of sales), representing the amount by which their carrying
value exceeds estimated fair value less cost to sell.

RECERTIFICATION COSTS AND DEFERRED DRYDOCK CHARGES

The Company's Marine Contracting vessels are required by regulation to be
recertified after certain periods of time. These recertification costs are
incurred while the vessel is in drydock where other routine repairs and
maintenance are performed and, at times, major replacements and improvements are
performed. The Company expenses routine repairs and maintenance as they are
incurred. Recertification costs can be accounted for in one of three ways: (1)
defer and amortize, (2) accrue in advance, or (3) expense as incurred. Companies
in the industry use either the defer and amortize or the expense as incurred
accounting method. The Company defers and amortizes recertification costs over
the length of time in which the recertification is expected to last, which is
generally 30 months. Major replacements and improvements, which extend the
vessel's economic useful life or functional operating capability, are
capitalized and depreciated over the vessel's remaining economic useful life.
Inherent in this process are estimates the Company makes regarding the specific
cost incurred and the period that the incurred cost will benefit.

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. As of December 31, 2004 and 2003, capitalized deferred drydock
charges (included in other assets, net) totaled $10.0 million and $7.3 million,
respectively. During the years ended December 31, 2004, 2003 and 2002, drydock
amortization expense was $4.9 million, $4.1 million and $4.9 million,
respectively.

ACCOUNTING FOR DECOMMISSIONING LIABILITIES

On January 1, 2003, the Company adopted Statement of Financial Accounting
Standards ("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 other than the $15.1 million of restricted cash in escrow (see
Statement of Cash Flow Information in this footnote).

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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):

The following table describes the changes in the Company's asset retirement
obligations for the year ended 2004 (in thousands):

Asset retirement obligation at December 31, 2003............ $78,414
Liability incurred during the period........................ 202
Liabilities settled during the period....................... (5,415)
Revision in estimated cash flows............................ 3,953
Accretion expense (included in depreciation and
amortization)............................................. 4,876
-------
Asset retirement obligation at December 31, 2004............ $82,030
=======

FOREIGN CURRENCY

The functional currency for the Company's foreign subsidiary, Cal Dive
International 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 $10.8 million and $5.0 million (net of taxes of $2.8 million in 2003),
respectively, is included in accumulated other comprehensive income, a component
of shareholders' equity. Beginning in 2004, deferred taxes have not been
provided on foreign currency translation adjustments since the Company considers
its undistributed earnings (when applicable) of its non-U.S. subsidiaries to be
permanently reinvested. As a result, cumulative deferred taxes on translation
adjustments totaling approximately $6.5 million were reclassified from
noncurrent deferred income taxes and accumulated other comprehensive income. All
foreign currency transaction gains and losses are recognized currently in the
statements of operations. These amounts for the years ended December 31, 2004
and 2003 were not material to the Company's results of operations or cash flows.

Canyon Offshore, the Company's ROV subsidiary, has operations in the
Europe/West Africa and Asia/ Pacific regions. 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, 2004 and 2003 were
not material to the Company's results of operations or cash flows.

54

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

The fair 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 2004 and 2003, the Company entered into various cash flow hedging
swap and costless collar contracts to stabilize 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 hedge instruments was a net liability of $876,000 and $2.2 million as of
December 31, 2004 and 2003, respectively. For the years ended December 31, 2004
and 2003 the Company recorded unrealized gains of approximately $846,000 and
$1.2 million, net of taxes of $456,000 and $654,000, respectively, in other
comprehensive income, a component of shareholders' equity as these hedges were
highly effective. The balance in the cash flow hedge adjustments account is
recognized in earnings when the hedged item is sold. During 2004 and 2003, the
Company reclassified approximately $11.1 million and $14.6 million,
respectively, of losses from other comprehensive income to Oil and Gas
Production revenues upon the sale of the related oil and gas production.

55

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2004, the Company has the following volumes under
derivative contracts related to its oil and gas producing activities:

Subsequent to December 31, 2004, the Company entered into additional oil
costless collars for the periods July through December 2005 and October through
December 2005. The July contract covers 20 MBbl per month at a price of $37.00
to $50.50 and the October contract covers 20 MBbl per month at a price of $37.00
to $50.80. The Company also entered into additional natural gas costless collars
for the period July through December 2005. The contracts cover 225,000 MMBtu per
month at a weighted average price of $5.00 to $9.44.

EQUITY INVESTMENTS

The Company periodically reviews its investments in Deepwater Gateway,
L.L.C. and Independence Hub, LLC for impairment. Recognition of a loss would
occur when the decline in an investment is other than temporary. In determining
whether the decline is other than temporary, the Company considers the cyclical
nature of the industry in which the investments operate, their historical
performance, their performance in relation to their peers and the current
economic environment. During 2004 and 2003 no impairment indicators existed.

EARNINGS PER SHARE

Basic earnings per share ("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):

56

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Stock options to purchase approximately 1,027,000 shares and 260,000 shares
for the years ended December 31, 2003 and 2002, respectively, were not dilutive
and, therefore, were not included in the computations of diluted income per
common share amounts. There were no antidilutive shares in 2004. In addition,
approximately 510,000 shares attributable to the convertible preferred stock
were excluded in the year ended December 31, 2004, calculation of diluted EPS,
as the effect was antidilutive. Further, approximately 1,111,000 shares
attributable to the convertible preferred stock were excluded in the year ended
December 31, 2003, calculation of diluted EPS, as the effect was antidilutive.
Net income for the diluted earnings per share calculation for the year ended
December 31, 2004 was adjusted to add back the preferred stock dividends and
accretion on the 1,022,000 shares.

STOCK BASED COMPENSATION PLANS

The Company uses the intrinsic value method of accounting 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 and all other provisions are fixed.
The following table reflects the Company's pro forma results if the fair value
method had been used for the accounting for these plans (in thousands, except
per share amounts):

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 2004, 2003 and 2002, and expected
volatility to be 56 percent in 2004 and 2003, and 59 percent in 2002. 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 2004, 2003 and 2002 was $17.59, $12.74 and
$15.20, 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 on 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 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. The Company
recognizes additional contract revenue related to claims when the claim is
probable and legally enforceable. 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, 2004 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.

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS

Accounts receivable are stated at the historical carrying amount net of
write-offs and allowance for uncollectible accounts. The Company establishes an
allowance for uncollectible accounts receivable based on historical experience
and any specific customer collection issues that the Company has identified.
Uncollectible accounts receivable are written off when a settlement is reached
for an amount that is less that the outstanding historical balance or when the
Company has determined the balance will not be collected.

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

58

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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: 2004 -- Louis
Dreyfus Energy Services (11%) and Shell Trading (US) Company (10%);
2003 -- Shell Trading (US) Company (10%) and Petrocom Energy Group, Ltd. (10%);
and 2002 -- Horizon Offshore, Inc. (10%) and BP Trinidad & Tobago LLC (11%).
Louis Dreyfus Energy Services, Shell Trading (US) Company and Petrocom Energy
Group, Ltd. were purchasers of ERT's oil and gas production. In March 2004, the
Company elected not to renew its alliance with Horizon Offshore, Inc. As part of
the settlement of outstanding trade accounts receivable with Horizon, the
Company obtained exclusive use of a Horizon spoolbase facility for a period of
five years. Utilization of the spoolbase facility was valued at approximately
$2.0 million with the Company offsetting a corresponding amount of trade
accounts receivable in exchange for the utilization agreement. The value of the
spoolbase facility is being amortized over the five year term of the agreement.
Trade receivables from Horizon at December 31, 2004 and 2003 were approximately
$3.3 million and $11.0 million, respectively.

INCOME TAXES

Deferred income taxes are based on the differences 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. The Company considers the undistributed earnings of
its non-U.S. subsidiaries to be permanently reinvested. At December 31, 2004,
the Company's non-U.S. subsidiaries had an accumulated deficit of $8.9 million
in earnings and profits. These losses are primarily due to timing differences
related to fixed assets. The Company has not provided deferred U.S. income tax
on the losses.

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 was released
in March 2004. As of December 31, 2004, the Company had $22.6 million of
restricted cash included in other assets, net, of which $15.1 million related to
ERT's escrow funds for decommissioning liabilities associated with the South
Marsh Island 130 ("SMI 130") field acquisitions in 2002. Under the purchase
agreement, ERT is obligated to escrow 50% of production up to the first $20
million and 37.5% of production on the remaining balance up to $33 million in
total escrow. Once the escrow reaches $10 million, ERT may use the restricted
cash for decommissioning the related fields. Additionally, $7.5 million was
included in restricted cash in other assets, net at December 31, 2004 related to
the Company's investment in Deepwater Gateway, L.L.C. The Company is required to
escrow up to $22.5 million related to its guarantee under the term loan
agreement for Deepwater Gateway, L.L.C. See footnote 6.

During the years ended December 31, 2004, 2003 and 2002, the Company made
cash payments for interest charges totaling $3.2 million, $2.7 million and
$811,000, respectively, net of capitalized interest.

RECENTLY ISSUED ACCOUNTING PRINCIPLES

In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based
Payment ("SFAS No. 123R"), which replaces SFAS No. 123, Accounting for
Stock-Based Compensation, ("SFAS No. 123") and supercedes APB Opinion No. 25,
Accounting for Stock Issued to Employees.

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SFAS No. 123R requires all share-based payments to employees, including grants
of employee stock options, to be recognized in the financial statements based on
their fair values beginning with the first interim or annual period after June
15, 2005, with early adoption encouraged. The pro forma disclosures previously
permitted under SFAS No. 123 no longer will be an alternative to financial
statement recognition. The Company is required to adopt SFAS No. 123R in the
third quarter of fiscal 2005, beginning July 1, 2005. Under SFAS No. 123R, the
Company must determine the appropriate fair value model to be used for valuing
share-based payments, the amortization method for compensation cost and the
transition method to be used at date of adoption. The transition methods include
prospective and retroactive adoption options. Under the retroactive option,
prior periods may be restated either as of the beginning of the year of adoption
or for all periods presented. The prospective method requires that compensation
expense be recorded for all unvested stock options and restricted stock at the
beginning of the first quarter of adoption of SFAS No. 123R, while the
retroactive methods would record compensation expense for all unvested stock
options and restricted stock beginning with the first period restated. The
Company has not yet determined the method of adoption of SFAS No. 123R. The
Company is evaluating the requirements of SFAS No. 123R and expects that the
adoption of SFAS No. 123R will not have a material impact on the Company's
consolidated results of operations and earnings per share.

SFAS No. 153, Exchanges of Nonmonetary Assets, an Amendment of APB Opinion
No. 29. In December 2004, the FASB issued SFAS No. 153, which is effective for
the Company for asset-exchange transactions beginning July 1, 2005. Under APB
29, assets received in certain types of nonmonetary exchanges were permitted to
be recorded at the carrying value of the assets that were exchanged (i.e.,
recorded on a carryover basis). As amended by SFAS No. 153, assets received in
some circumstances will have to be recorded instead at their fair values. In the
past, the Company has not engaged in a large number of nonmonetary asset
exchanges for significant amounts.

3. OFFSHORE PROPERTY TRANSACTIONS

As an extension of ERT's well exploitation and PUD strategies, ERT agreed
to participate in the drilling of an exploratory well to be drilled in 2005 that
targets reserves in deeper sands, within the same trapping fault system, of a
currently producing well with estimated drilling costs of approximately $20
million, of which $1.1 million of equipment costs had been incurred through
December 31, 2004. If the drilling is successful, ERT's share of the development
cost is estimated to be an additional $15 million. CDI's Marine Contracting
assets would participate in this development.

In March 2005, ERT acquired a 30% working interest in a proven undeveloped
field in Atwater Valley Block 63 of the deepwater Gulf of Mexico for cash
consideration and assumption of certain decommissioning liabilities. ERT's
expected share of development costs for 2005 through 2007 are approximately $70
million to $100 million.

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, 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.

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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 $26.7 million, $16.4 million and $9.2
million for the years ended December 31, 2004, 2003 and 2002 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.

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. 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.
Production began in December 2003. Payments to OKCD from ERT totaled $20.3
million in the year ended December 31, 2004. 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.

During 2003, the Company was paid $2.2 million, by Ocean Energy, Inc.
("Ocean"), an oil and gas industry customer, for marine contracting services. A
member of the Company's board of directors was a member of senior management of
Ocean (now part of Devon Energy Corp.).

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

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

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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 long-term
debt 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 2004 and 2003, the Company
purchased approximately one-third and one-third, respectively, of the redeemable
shares at the minimum purchase price of $13.53 per share. Consideration included
approximately $344,000 and $400,000 of contingent consideration relating to tax
gross-up payments paid to the Canyon employees in accordance with the purchase
agreement. These gross-up amounts were recorded as goodwill in the period paid
(i.e., the second quarters of 2004 and 2003). As of December 31, 2004, goodwill
related to the Canyon acquisition was approximately $44.8 million.

CAL DIVE INTERNATIONAL LIMITED (FORMERLY KNOWN AS 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).
Cal Dive International 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 ($24.4 million as of December 31, 2004). The results of Cal
Dive International Limited are included in the accompanying statements of
operations since the date of the purchase, July 1, 2002.

6. INVESTMENTS IN PRODUCTION FACILITIES

In June 2002, CDI, along with Enterprise Products Partners L.P.
("Enterprise"), formed Deepwater Gateway, L.L.C. 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. CDI's share of the construction costs was approximately $120
million, all of which had been incurred as of December 31, 2004. In August 2002,
the Company along with Enterprise, completed a non-recourse project financing
for this venture, terms of which include a minimum equity investment in
Deepwater Gateway, L.L.C. of $33 million, all of which had been paid as of
December 31, 2004, and is recorded as Investments in Production Facilities in
the accompanying consolidated balance sheet. The Company's investment in
Deepwater Gateway, L.L.C. totaled $56.6 million as of December 31, 2004.
Included in the investment account was capitalized interest and insurance paid
by the Company totaling approximately $2.6 million. In June 2004, the Deepwater
Gateway, L.L.C. construction loan, excluded from the Company's long-term debt,
was converted to a term loan. The term loan is collateralized by substantially
all of Deepwater Gateway, L.L.C.'s assets and is non-recourse to the Company
except for the balloon payment due at the end of the term. In the event of
default, the Company would be required to pay up to $22.5 million; however, the
Company has

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not recorded any liability for this guarantee as management believes that it is
unlikely the Company will be required to pay the $22.5 million. In accordance
with terms of the term loan, Deepwater Gateway, L.L.C. has the right to repay
the principal amount plus any accrued interest due under its term loan at any
time without penalty. Deepwater Gateway, L.L.C. has decided to extinguish its
term loan. The Company and Enterprise will make equal cash contributions
(approximately $72 million each) to Deepwater Gateway, L.L.C. to fund the
repayment. At March 9, 2005, the term loan principal amount owed by Deepwater
Gateway, L.L.C. was $144 million.

Summary balance sheets of Deepwater Gateway, L.L.C. as of December 31, 2004
and 2003 were as follows (in thousands):

Summary statements of operations of Deepwater Gateway, L.L.C. for the years
ended December 31, 2004, 2003 and 2002 were as follows (in thousands):

Deepwater Gateway, L.L.C. operated as a development stage enterprise for
2003 and 2002. In 2004, Deepwater Gateway, L.L.C. exited development stage.

In December 2004, CDI acquired a 20% interest in Independence Hub, LLC
("Independence"), an affiliate of Enterprise. Independence will own the
"Independence Hub" platform to be located in Mississippi Canyon block 920 in a
water depth of 8,000 feet. Independence has previously executed agreements with
the Atwater Valley Producers Group of five exploration and production companies
for the dedication and processing of natural gas and condensate production from
fields in the Atwater Valley, DeSoto Canyon and Lloyd Ridge areas of the
deepwater Gulf of Mexico on the Independence Hub platform. As part of that
transaction, the producers have also dedicated future production from a number
of undeveloped blocks in the area for processing. The 105 foot deep draft,
semi-submersible platform will serve as a regional hub for natural gas
production from multiple ultra-deepwater fields in the previously untapped
eastern Gulf of Mexico. The platform, which is estimated to cost approximately
$385 million, will be capable of processing 850 million

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

cubic feet of gas per day. It is designed to process production from six anchor
fields and has excess payload capacity to tie back up to 10 additional fields.
CDI's initial investment of $10.6 million has been paid as of December 31, 2004,
and its total investment in Independence is expected to be approximately $77
million. Further, CDI is party to a guaranty agreement with Enterprise to the
extent of CDI's ownership in Independence (20% at December 31, 2004). The
agreement states, among other things, that CDI and Enterprise guarantee
performance under the Independence Hub Agreement between Independence and the
producers group of exploration and production companies up to $397.5 million,
plus applicable attorneys' fees and related expenses. CDI has estimated the fair
value of its share of the guarantee obligation to be immaterial at December 31,
2004 based upon the extreme remote possibility of payments being made under the
performance guarantee.

7. ACCRUED LIABILITIES

Accrued liabilities consisted of the following as of December 31, 2004 and
2003 (in thousands):

8. LONG-TERM DEBT

At December 31, 2004, $136.4 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 which began in August 2002 and
matures 25 years from such date. The MARAD Debt 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 2.47% as of December 31, 2004). CDI has paid MARAD
guarantee fees for this debt which adds approximately 50 basis points per annum
of interest expenses. 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, 2004 the Company was in
compliance with these covenants.

The Company had a $70 million revolving credit facility originally due in
February 2005. This facility was collateralized by accounts receivable and
certain of the Company's Marine Contracting vessels. All outstanding borrowings
under the facility were repaid during 2004 and the facility was cancelled and
terminated in August 2004 and replaced by the new $150 million revolving credit
facility described below.

In August 2004, the Company entered into a four-year, $150 million
revolving credit facility with a syndicate of banks, with Bank of America, N.A.
as administrative agent and lead arranger. The amount available under the
facility may be increased to $250 million at any time upon the agreement of the
Company

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

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and the existing or additional lenders. The new credit facility is secured by
the stock in certain Company subsidiaries and contains a negative pledge on
assets. The new facility bears interest at LIBOR plus 75 -- 175 basis points
depending on Company leverage and contains financial covenants relative to the
Company's level of debt to EBITDA, as defined in the credit facility, fixed
charge coverage and book value of assets coverage. As of December 31, 2004, the
Company was in compliance with these covenants and there was no outstanding
balance under this facility.

The Company had 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 was repaid in full in August 2004 and the loan
agreement was subsequently cancelled and terminated.

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%). 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 revolving credit
facility, which had initially funded the construction costs of the assets. This
transaction was accounted for as a capital lease with the present value of the
lease obligation (and corresponding asset) reflected on the Company's
consolidated balance sheet.

Deferred financing costs of $11.6 million ($3.6 million of which was
accrued at December 31, 2004 due upon the Company locking in a fixed rate of
interest on the MARAD Debt) related to the MARAD Debt and the revolving credit
facility, respectively, are being amortized over the life of the respective
agreements and are included in Other Assets, net as of December 31, 2004.

The Company incurred interest expense, net of amounts capitalized, of $5.6
million, $2.6 million and $2.3 million for the years ended December 31, 2004,
2003 and 2002, respectively.

Scheduled maturities of Long-term Debt and Capital Lease Obligations
outstanding as of December 31, 2004 were as follows (in thousands):

The Company had unsecured letters of credit outstanding at December 31,
2004 totaling approximately $3.7 million. These letters of credit primarily
guarantee various contract bidding and insurance activities.

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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,
2004 and 2003, is as follows (in thousands):

At December 31, 2004, the Company had $12.0 million of net operating
losses, $4.5 million of research and development credits and $1.0 million of
alternative minimum tax credits. $2.2 million of the net operating losses were
incurred in the United States and $9.8 million were incurred in the United
Kingdom. The credits were generated in the United States. The use of these net
operating losses and the credits is subject to limitations imposed by the tax
jurisdiction in which the loss or credit was generated and is also restricted to
the taxable income of the entity generating the loss or credit. The U.S. losses
if not utilized, will expire in 2022 and 2023. The U.K. losses have an
indefinite carryforward period. The research and development credits will expire
in the years 2018 through 2022. The alternative minimum tax credits have an
indefinite carryforward period.

The examination of the Company's 2001 and 2002 income tax returns by the
Internal Revenue Service ("IRS") was concluded in the first quarter of 2004. As
a result, the Company recorded an income tax benefit of $1.7 million during the
first quarter of 2004 primarily related to research and development credits
offset by $430,000 of interest expense related to timing differences with
respect to research and development deductions.

The IRS concluded its examination of the 2001 pre-acquisition income tax
return for Canyon in the second quarter of 2004. The resolution of this audit
did not have a material impact on the consolidated financial statements of the
Company.

In 2004, the Company paid $282,000 in cash taxes for adjustments to Canyon
Offshore Inc.'s 2001 U.S. Federal Income Tax return resulting from an IRS audit
of that return. The Company paid no cash taxes in 2002 or 2003.

The Company plans to file for a change in its tax method of accounting for
the timing differences that arise from the abandonment obligations assumed in
certain offshore property acquisitions. The accompanying financial statements
include an adjustment to account for the estimated amount of deferred tax
liability related to this timing difference as required under the current tax
accounting rules. At December 31, 2004 and 2003, the adjustment resulted in a
decrease of $20.7 million and $16.4 million, respectively, in the deferred tax

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CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

assets and liabilities for the timing differences related to abandonment
obligations and fixed assets and a corresponding decrease of $20.7 million and
$16.4 million, respectively, in the deferred tax asset related to net operating
losses. This change has no impact on the net deferred tax liability of the
Company.

The Company considers the undistributed earnings of its non-U.S.
subsidiaries to be permanently reinvested. At December 31, 2004, the Company's
non-U.S. subsidiaries had an accumulated deficit of $8.9 million in earnings and
profits. These losses are primarily due to timing differences related to fixed
assets. The Company has not provided deferred U.S. income tax on the losses.

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. Subsequently in June
2004, the preferred stockholder exercised its existing right and purchased $30
million in additional cumulative convertible preferred stock (Series A-2
Cumulative Convertible Preferred Stock, par value $0.01 per share). In
accordance with the January 8, 2003 agreement, the $30 million in additional
preferred stock is convertible into 982,029 shares of Cal Dive common stock at
$30.549 per share. In the event the holder of the convertible preferred stock
elects to redeem into Cal Dive common stock and Cal Dive's common stock price is
below the conversion prices unless the Company has elected to settle in cash,
the holder would receive additional shares above the 833,334 common shares
(Series A-1 tranche) and 982,029 common shares (Series A-2 tranche). The
incremental shares would be treated as a dividend and reduce net income
applicable to common shareholders.

The preferred stock has a minimum annual dividend rate of 4%, subject to
adjustment, payable quarterly in cash or common shares at Cal Dive's option. CDI
paid these dividends in 2004 and 2003 on the last day of the respective quarter
in cash. After the second anniversary of the original issuance, the holder may
redeem the value of its original and additional 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.

The proceeds received from the sales 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 accreted
through the statement of operations through December 31, 2004. 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 for the original $25 million issuance and on
the date of issuance (June 25, 2004) for the additional $30 million. Beginning
in 2005, both tranches of preferred stock will be based on the lower of the
Company's share price at the beginning of the applicable period or the
applicable conversion price ($30.00 and $30.549).

11. COMMITMENTS AND CONTINGENCIES

LEASE COMMITMENTS

The Company leases several facilities, ROVs and a vessel under
noncancelable operating leases. Future minimum rentals under these leases are
approximately $12.0 million at December 31, 2004 with $3.3 million due in 2005,
$1.1 million in 2006, $1.1 million in 2007, $892,000 in 2008, $889,000 in 2009
and $4.7 million thereafter. Total rental expense under these operating leases
was approximately $8.9 million, $8.1 million and $6.9 million for the years
ended December 31, 2004, 2003 and 2002, respectively.

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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 Intrepid, Seawell and 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 and other insurance 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 $9.5 million and $3.3 million as of December 31, 2004 and 2003,
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 incurs 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 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. One of the grounds in the preliminary findings by the
arbitrator is applicable to CDO, and CDO holds substantial counterclaims against
Seacore.

During 2002, the Company engaged in a large construction project offshore
Trinidad 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 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 customer has disputed these invoices along with
certain other change orders. In May 2004, the Company and its customer settled
certain elements of the dispute. Of the amounts billed by CDI for this project,
$6.8 million had not been collected as of December 31, 2004. This matter settled
in March 2005 with no material effect on the Company's financial position or
results of operations.

Although the above discussed matters have the potential of significant
additional liability, the Company believes 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.

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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 $691,000, $785,000 and $811,000 for the years ended
December 31, 2004, 2003 and 2002, 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.

On January 3, 2005, the Company granted certain key executives and selected
management employees 94,000 restricted shares under the Incentive Plan. The
shares vest 20% per year for a five year period. The market value (based on the
quoted price of the common stock on the date of grant) of the restricted shares
was $39.12 per share, or $3.7 million, at the date of the grant and will be
recorded as unearned compensation, a component of shareholders' equity. This
amount will be charged to expense over the respective vesting period.

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 46,790, 52,572 and 44,158 shares of common stock were purchased
in the open market at a weighted average share price of $27.15, $21.74 and
$21.86 during 2004, 2003 and 2002, respectively.

All of the options outstanding at December 31, 2004, have exercise prices
as follows: 104,000 shares at $17.14, 118,000 shares at $19.63, 205,000 shares
at $21.38, 131,035 shares at $21.83, 91,400 shares at $24.00, 124,500 shares at
$24.36, 80,000 shares at $26.75 and 446,012 shares ranging from $16.45 to $27.82
and a weighted average remaining contractual life of 6.41 years.
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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.

Included in accumulated other comprehensive income (loss) at December 31,
2004 was an unrealized loss on commodity hedges, net of $581,000 and an
unrealized gain on foreign currency translation adjustments of $18.4 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.

14. BUSINESS SEGMENT INFORMATION (IN THOUSANDS)

The Company's operations are conducted through three primary reportable
segments, Marine Contracting, Oil and Gas Production and Production Facilities.
The Company evaluates its performance based on income before income taxes of
each segment. Segment assets are comprised of all assets attributable to the
reportable segment The Company's Production Facilities segment (Deepwater
Gateway, L.L.C. and Independence Hub, LLC) is accounted for under the equity
method of accounting.

The following summarizes certain financial data by business segment:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) Included pre-tax $3.9 million of asset impairment charges in 2004.

During the years ended December 31, 2004 and 2003, the Company derived
approximately $77.1 million and $48.4 million, respectively, of its revenues
from the U.K. sector utilizing approximately $136.7 million and $117.1 million,
respectively, of its total assets in this region. 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).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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, 2004, 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

73

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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. As of December 31, 2004, 4,088,358 Bbls of
oil and 16,842,700 MCf of gas were undeveloped, 41% 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:

74

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. ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS

The following table sets forth the activity in the Company's Allowance for
Uncollectible Accounts for each of the three years in the period ended December
31, 2004 (in thousands):

See Note 2 for a detailed discussion regarding the Company's accounting
policy on Accounts Receivable and Allowance for Uncollectible Accounts and Note
11 for a discussion of a large construction project in 2002.

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 2004 and 2003.

75

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

76

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, 2004. 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, 2004 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.

Management's Report on Internal Control Over Financial Reporting and the
Report of Independent Registered Public Accounting Firm on Internal Control Over
Financial Reporting thereon are set forth in Part II, Item 8 of the Annual
Report on Form 10-K on page 44 and page 46, respectively. There were no changes
in the Company's internal control over financial reporting that occurred during
the fiscal quarter ended December 31, 2004 that have materially affected, or are
reasonably likely to materially affect, the Company's internal control over
financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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 2005 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 2005 Annual
Meeting of Shareholders.

77

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

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 2005 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 2005 Annual
Meeting of Shareholders.

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 2005 Annual
Meeting of Shareholders.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(1) Financial Statements

The following financial statements included on pages 43 through 76 in this
Annual Report are for the fiscal year ended December 31, 2004.

Management's Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm on Internal
Control Over Financial Reporting
Consolidated Balance Sheets as of December 31, 2004 and 2003
Consolidated Statements of Operations for the Years Ended December 31,
2004, 2003 and 2002
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 2004, 2003 and 2002
Consolidated Statements of Cash Flows for the Years Ended December 31,
2004, 2003 and 2002
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) 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.

80

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 15, 2005

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.

81

INDEX TO EXHIBITS

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

* Filed herewith.