CAL DIVE INTERNATIONAL INC - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

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

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NO. 0-22739

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

MINNESOTA 95-3409686
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 N. SAM HOUSTON PARKWAY E.,
SUITE 400
HOUSTON, TEXAS 77060
(Address of Principal Executive Offices) (Zip Code)

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. 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. [ ]

The aggregate market value of the voting stock held by non-affiliates of
the registrant as of March 26, 2002 was $730,016,396 based on the last reported
sales price of the Common Stock on March 26, 2002, as reported on the
NASDAQ/National Market System.

The number of shares of the registrant's Common Stock outstanding as of
March 25, 2002 was 32,476,880.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement for the Annual Meeting of
Shareholders to be held on May 15, 2002 are incorporated by reference into Part
III hereof.
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CAL DIVE INTERNATIONAL, INC. ("CDI") INDEX -- FORM 10-K

1

PART I

ITEM 1. BUSINESS.

OVERVIEW

We are a leading energy services company involved in projects from the
shallowest to the deepest waters of the Gulf of Mexico. We have a reputation for
innovation in our subsea construction techniques, equipment design and methods
of partnering with customers. Our diversified fleet of 23 vessels and 19
remotely operated vehicles (ROVs) performs services that support drilling, well
completion, construction and decommissioning projects involving pipelines,
production platforms, risers and subsea production systems. We also acquire
interests in natural gas and oil properties and related production facilities as
part of our Production Partnering business. Our customers include major and
independent natural gas and oil producers, pipeline transmission companies and
offshore engineering and construction firms.

We have positioned for work in water depths greater than 1,000 feet (the
"Deepwater") by assembling a technically advanced fleet of dynamically
positioned (DP) vessels and ROVs and a highly experienced group of support
professionals. Our DP vessels serve as work platforms for subsea solutions
provided by us working with our alliance partners, a team of internationally
recognized contractors and manufacturers. Our new ROV subsidiary, Canyon
Offshore, Inc., offers survey, engineering, repair, maintenance and
international cable burial services. We are also a leader in solving the
challenges encountered in Deepwater construction, with many of our projects
using methods we have developed. Most notably, our newest and most advanced
Deepwater semi-submersible multi-service vessel ("MSV"), the Q4000, incorporates
our latest patented technologies. We anticipate that the Q4000 will improve
Deepwater completion and construction economics for our customers. Availability
of our Q4000, Eclipse and Mystic Viking, together with the soon to be completed
Intrepid (formerly Sea Sorceress), will result in CDI offering the largest
permanently deployed fleet of DP vessels in the Gulf of Mexico (GOM).

On the Outer Continental Shelf (OCS) in water depths up to 1,000 feet, we
perform traditional subsea services, including air and saturation diving and
salvage work. Our subsidiary, Aquatica, Inc., provides full compliment services
in the shallow water market from the shore to 300 fsw. The acquisition of the
assets of Professional Divers of New Orleans, Inc. early in 2001 added important
vessel and offshore personnel capacity. In the OCS "spot market", projects are
generally turnkey in nature, short in duration (two to thirty days) and require
constant rescheduling and availability of multiple vessels. Fifteen of our
vessels perform traditional diving services and six of them support saturation
diving. The technical and operational experience of our personnel and the
scheduling flexibility offered by our large fleet enables us to manage turnkey
projects to satisfy customers' requirements and achieve our targeted
profitability. We have also established a leading position in the salvage market
by offering customers a number of options to address decommissioning obligations
in a cost-efficient manner, particularly in the removal of smaller structures.
Our alliance with Horizon Offshore, Inc. provides derrick barge and heavy lift
capacity for the removal of larger structures.

In our Production Partnering business, our subsidiary Energy Resource
Technology, Inc. ("ERT") is one of a few companies with the skills required to
profitably acquire and operate mature natural gas and oil properties in the
Gulf. The reservoir engineering and geophysical disciplines of ERT also enabled
us to acquire a working interest in the Gunnison prospect, a Gulf Deepwater oil
and natural gas exploration project in partnership with the operator Kerr-McGee
Oil & Gas Corporation. We anticipate that this investment will both generate
significant income in the future and will also help secure utilization for our
subsea assets. As this project has now been sanctioned, we are already
participating in field development planning and will collaborate with the other
working interest owners in executing subsea construction work. We plan to again
expand our Partnering strategy through our recent Letter of Intent to
participate in the ownership of the Marco Polo production facility. Owning 50%
of this proposed tension-leg platform in a joint venture with El Paso Energy
Partners, when financed, would be designed to generate good returns and also
have upside potential for both our construction work and ERT farm-in
opportunities.

Our overall corporate goal has been to increase shareholder value by
focusing on strengthening our market position to provide a return which leads
our peer group. Our return on capital employed (ROCE) in
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2001 was 12% in contrast to the 4% average of our peer group; we have averaged
an ROCE of 16% over the past five years versus the 6% average of our peers. We
have been able to achieve our ROCE objective by focusing on the following
business strengths and strategies:

OUR STRENGTHS

Diversified Fleet of Vessels and ROVs: Our fleet is the largest
permanently deployed in the GOM and has one of the most diverse and technically
advanced collections of subsea construction, maintenance and decommissioning
project capabilities. These comprehensive services provided by our vessels are
both complementary and overlapping, enabling us to assure customers the
redundancy essential for most projects but especially in the Deepwater. Our new
ROV based remote systems capabilities are critical to Deepwater construction and
well intervention operations and Canyon's submarine cable burial business
provides a platform for international operations and revenue diversification.

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

Major Provider of Marine Construction Services on the OCS: We believe that
our expansion of Aquatica, our alliance with Horizon and our dominant position
in the GOM for saturation diving services makes us the largest supplier of such
services on the OCS. Depletion of existing reserves, coupled with increased
demand for natural gas, should require exploitation and development of OCS
reservoirs.

Production Partnering: The strategy of ERT's gas production business
differentiates us from our competitors and helps to offset the cyclical nature
of our marine construction operations. ERT's acquisition, sale and exploitation
programs for mature properties on the OCS will be greatly expanded by the
ownership of Deepwater assets such as the Gunnison project and the Marco Polo
facility prospect.

Leader in Decommissioning Operations: Over the last decade, we have
established a leading position in decommissioning offshore facilities,
particularly in the removal of the smaller structures and caissons which make up
52% of the market. 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: We will continue to focus on the GOM basin, where we
have provided marine construction services since 1975. We expect natural gas and
oil exploration and development activity in the Gulf, particularly in the
Deepwater regions, to increase significantly in the next several years.

Capturing a Significant Share of the Deepwater Market: We expect to
benefit from the anticipated increase in Deepwater Gulf activity through our
expanded fleet of seven DP vessels, the most any company has permanently
deployed in the Gulf. Together with our alliance partners, we provide customers
integrated solutions which minimize project duration and cost.

Develop Well Operations Niche: We are employing more Deepwater assets,
construction techniques and technologies focused upon servicing upstream market
niches, such as pre-drilling services, well operations and vessels that offer
cost-effective alternatives to services generally provided by drilling rigs.
Examples include: the enhanced well intervention and completion design of the
Q4000 and Uncle John and; the pipelay and platform support capability of the
Eclipse and Intrepid. GOM well operations is a new niche for us. We believe the
modification of the Q4000 will prove economically advantageous to our customers
needing this service.

Building Alliances to Expand the Scope of Our Services and Technology: We
have alliance agreements with a team of domestic and internationally recognized
contractors and manufacturers. These alliances enable us to offer
state-of-the-art products and services while maintaining our low overhead base.

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Maximizing the Value of Mature Natural Gas and Oil Properties: Through
ERT, we acquire and produce mature, non-core offshore property interests,
offering customers a cost-effective alternative for customers to the
decommissioning process. Since its inception in 1992, ERT has delivered a 30%
average annual return on its invested capital.

Partnering with Customers: In 2000, we expanded the ERT business strategy
to Deepwater prospects through a 15% equity participation in the Gunnison
prospect. Total Proven reserves at 2001 year-end grew to 100 BCFe with initial
reserves of 76.5 BCFe assigned to our ownership position in Gunnison. Our
recently announced Letter of Intent to own 50% of the tension-leg platform at
Anadarko's Marco Polo field, when financed, could extend the concept of
acquiring oil and gas assets to earn a return while also securing the associated
marine construction work.

SUMMARY OF 2001 DEVELOPMENTS

THIS "SUMMARY OF 2001 DEVELOPMENTS" IS INCOMPLETE BY IT NATURE, MAY OMIT
MATERIAL INFORMATION, AND IS QUALIFIED IN ITS ENTIRETY BY MORE DETAILED
INFORMATION CONTAINED ELSEWHERE IN THIS FORM 10-K, INCLUDING THE FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA.

By most measures, 2001 was an outstanding year for us even though commodity
prices plummeted and a significant increase in offshore construction activity
failed to materialize. As a result, we were able to achieve most of our stated
2001 goals, including:

i. Financial: Delivered ROCE of 12%.

ii. Deepwater Contracting: Purchased additional Deepwater assets.

iii. Well Operations: Undertook Q4000 enhancements.

iv. Production Contracting: Gunnison sanctioned and identified our
Marco Polo prospect.

v. OCS: Acquired additional assets and extended the Horizon Alliance.

vi. Safety: Implemented an enhanced EHS management system.

In 2001, for a second time, Forbes magazine named us one of America's 200
best small companies. Our ranking was 109th overall, and we were one of only two
oilfield service companies to qualify for this year's list. Articles
accompanying the October 29 issue note that the sliding economy reshaped what it
meant to be among the best small companies. Rankings were based on six equally
weighted metrics: return on equity, sales and earnings-per-share growth, each
measured over the past five years and the most recent four quarters. As a
result, fewer than 1% of eligible companies made this list. We believe our
ability to grow sales and earnings through a decline in the market for offshore
services, while delivering a five-year average return on capital of 16%,
highlights the value of our counter-cyclical strategy. This counter-cyclical
strategy, whereby we acquire interests in oil and gas properties to secure the
related marine contracting work, provides a natural hedge in energy industry
downturns.

HIGHLIGHTS OF 2001 OPERATING DEVELOPMENTS:

2001 was a roller-coaster year in our market for many reasons, including
commodity prices. We believe, however, that three basic factors work in favor of
our long-term business model: (i) the Deepwater GOM is an oil play with many
large projects "on-course" despite the prices; (ii) the decline in natural gas
prices should provide ERT and our Production Partnering strategy with more
opportunities; and (iii) Gunnison will provide subsea construction work and then
production related cash to fund growth.

DEEPWATER CONTRACTING

In anticipation of developments relating to our long-term business plan in
the Deepwater, we had success in four areas in 2001: expansion of non-U.S.
markets; acquiring more Deepwater vessels; acquiring our ROV

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subsidiary, Canyon, and; implementing our Well Operations Group. Overall
revenues in this segment were just under $80 million or 35% of our consolidated
total revenue (up from 28% in 2000).

Our decision to accelerate regulatory inspections in 2000 proved useful in
achieving 87% utilization (vs 56% in 2000) for our deepwater vessels,
particularly the Witch Queen and the Uncle John. The Witch Queen worked in
Mexican waters for Horizon/Pemex for 14 consecutive months through the third
quarter, then mobilized to Trinidad for BP and other customers. The Merlin
provided ROV support to the Allseas Lorelay pipelay vessel for its summer
campaign and then was involved in the large Nansen/Boomvang project. After her
May acquisition, the Mystic Viking was deployed in Mexican waters for the second
half of the year. All work was performed well and represents the potential of
future growth in these non-U.S. markets.

With GOM work for our vessels available but world construction activity
low, we took the opportunity to grow our fleet to service Deepwater projects.
The Mystic Viking purchase replaced the Balmoral Sea with more capacity. In
October, we announced the purchase of the Eclipse, a large mono-hull with
significant deck load capacity. These vessels together with our exiting fleet
provide seven world class DP vessels to help assure scheduling flexibility for
the technological challenges of Deepwater.

As another part of our Deepwater puzzle, we purchased the ROV business of
our new subsidiary, Canyon. Canyon represents an integration which is consistent
with our policy of directly controlling all aspects on the critical path of
significant projects. As marine construction support in the Gulf of Mexico moves
to deeper waters, ROV systems will play an increasingly important role. Canyon
currently owns 18 ROV systems and operates seven others in three regions: United
States (13), Southeast Asia (8), and the North Sea (4). It also operates eight
trenching systems internationally, including four customer-owned units.

In the second and third quarters, our newly assembled team of well
operation specialists, working in tandem with Alliance partner Schlumberger from
the Uncle John work platform, tackled intervention projects at three subsea
wells. Each job involved through-tubing, subsea well decommissioning operations
employing slickline, E-line, cementing, coiled tubing and fluid handling
services. The Uncle John worked every available day during the year (93%
utility) because of her flexibility to perform both well intervention and marine
construction operations. We believe this highlights potential market demand for
well operations work by the Q4000. Other major well operations projects
completed during 2001 include: Conoco -- world's first use of the Schlumberger
Sen Tree 3 system as an open water riser system from a DP vessel in a shallow
water live well intervention; and FMC -- jointly developed the world's first
15,000 psi intervention riser for operations to 10,000 fsw. In addition, the
2001 Deepwater geotechnical coring campaign with Alliance partner Fugro involved
work at Gunnison, Thunderhorse (formerly Crazy Horse), Holstein and Devil's
Tower among others.

SHELF CONTRACTING

In our OCS business, Aquatica delivers our services in the shallow water
market (from the beach to 300 fsw). In March 2001, Aquatica acquired
substantially all of the assets of Professional Divers which included three
utility vessels and a four-point moored DSV. OCS revenues increased at a rapid
pace during 2001 in response to both a spike in drilling activity and the
doubling of our DSV fleet for a second year in a row -- this time from five
vessels to ten. The call-out nature of this business allows us to adjust rates
quickly as market conditions develop. These factors combined to generate $37
million of 2001 revenues, an 80% improvement over the prior year.

In early 2001, our OCS Alliance with Horizon Offshore was extended for
three years. Under the Alliance, we provide DSVs to support Horizon pipelay
barges while Horizon supplies, derrick barge and heavy lift capacity to us. In
addition, we took over all Horizon barge diving effective May 1, a low-margin
activity we view as a contribution to the success of the alliance. Three of our
DSVs work the Outer Continental Shelf virtually all in support of Horizon
pipelay activity. This alliance and our work together in Mexico resulted in
Horizon becoming our largest customer, accounting for 18% of revenues in 2001.

For the second consecutive year OCS salvage revenues and margins were
disappointing. In part, this is a result of high commodity prices in 2000 that
led producers to push the last possible production out of their older
properties. Because of the decline in commodity prices during 2001, these
properties are now appearing

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on the market with negative asset values. As a result, we expect that many will
go directly to decommissioning, a development that suggests increased salvage
demand in 2002 and 2003.

Finally, we introduced a company-wide effort to enhance our behavioral
safety process (BSP) and training that makes safety a constant focus of
awareness through open communication with all offshore and yard employees. First
year results from this program were impressive as our safety rating improved
dramatically in 2001.

PRODUCTION PARTNERING

This segment which differentiates us from our Peer Group, was part of the
2001 commodity based roller-coaster. In the first part of the year, ERT
contributed significantly to our earnings due to high production and realized
gas prices before prices collapsed in the second half. Gas and oil revenues of
$63.4 million declined by 10% with virtually all of that attributable to
production of 13.9 BCFe versus 15.5 BCFe the prior year. Fortunately, production
was at the high end of our expectation (14BCFe) without the benefit of
significant acquisitions. ERT's management team did an outstanding job
conducting an aggressive and successful exploitation program resulting in near
replacement of reserves. 2001 closed with 24.5 BCFe of proven reserves in
contrast to 28.2 BCFe a year earlier.

Also in 2001, our Deepwater ERT plan succeeded as initial reserves of 76.5
BCFe were assigned to our ownership position in Gunnison. This figure represents
15% of the reserves reported by the operator, Kerr-McGee Oil & Gas Corporation,
at December 31, 2001. The affiliated limited partnership that assumed the
exploratory risk funded $21.5 million of drilling costs, considerably above the
initial $15 million estimate. Our share of the ensuing project development costs
is estimated in a range of $100 million to $110 million with over half of that
for construction of the spar. The full potential of the three Gunnison blocks
will be better defined a year from now as the operator plans an extensive
development program in 2002. The development timetable schedules our marine
construction activities for 2003 with first production anticipated early in
2004. The field is now expected to begin production in 2004.

During 2001 we took another step to expanding our Production Partnering
concept by signing a Letter of Intent to own 50% of the Marco Polo production
facility at 4300 fsw. When financed, we would assist with the installation of
the tension-leg platform which would be operated with El Paso Energy Partners on
a fixed-fee-plus-tariff basis.

INTRODUCTION TO SUBSEA CONSTRUCTION

The offshore oilfield services industry in the Gulf 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
natural gas and oil industry has increasingly relied upon these fields for new
production. The oilfield services industry benefits from a number of trends
including the following:

- Lack of growth in natural gas production and failure to construct new
assets in the face of foreign dependency and increasing demand.

- Advances in exploration, extraction and production technology that have
enabled industry participants to more cost-effectively enter the Gulf
Deepwater.

- Increased demand for decommissioning services as the offshore natural gas
and oil continues to mature.

In response to the natural gas and oil industry's migration to the
Deepwater, equipment and vessel requirements have changed. Most vessels
currently operating in the Deepwater Gulf were designed in the 1970s and 1980s
for work in a maximum depth of approximately 1,000 feet. These vessels have been
modified to take advantage of new technologies and now operate in depths up to
4,000 feet. We believe there is unmet demand in the Gulf for new generation
vessels, such as the Q4000 and Intrepid, that are specifically designed to work
in water depths up to 10,000 feet.

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

BCFe: When describing oil and natural gas, the term converts oil
volumes to their energy equivalent in natural gas and combines them in
billions of cubic feet equivalent (BCFe).

Deepwater: Water depths beyond 1,000 feet fsw.

Dive Support Vessel (DSV): Specially equipped vessel which 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 enable 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.

EBITDA: Earnings before interest, taxes, depreciation and
amortization is a supplemental financial measure of cash flow used in the
evaluation of the marine construction industry.

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

E&P: Companies involved in oil and gas exploration and production
activities.

Full Field Development: The ability to offer to oil and gas companies
a range of services from subcontracting to complete field development
solutions. These include procurement and installation of flowlines,
wellheads, control systems, umbilicals and manifolds, as well as
installation and commissioning of the complete production system. Many oil
and gas companies prefer to contract with a company capable of undertaking
the entire field development project or major portions of it. Full field
development services can relieve a customer of substantial management
burdens.

Life of Field Services: Includes services performed on 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 government regulatory body
having responsibility for United States waters in the Gulf.

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.

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

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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ROCE: Return on Capital Employed is the amount, expressed as a
percentage, earned on a company's total capital (shareholders' equity plus
long-term debt). It is calculated by dividing earnings before interest and
dividends by total capital.

Saturation Diving: Saturation diving, required for work in water
depths between 300 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 seabed 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.

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.

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

SUBSEA CONTRACTING

We and our alliance partners provide a full range of subsea construction
services, including the following, in both the OCS and Deepwater Gulf:

- 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. Our fleet consists of: two
(2) semi-submersible DP MSVs (the Q4000 and Uncle John); two (2) construction DP
DSVs (the Witch Queen and Mystic Viking); two (2) larger mono-hull pipelay and
constructions vessels (the Intrepid and the Eclipse) and two (2) ROV support
vessels (the Merlin and the Northern Canyon). In 2001, vessel enhancements
included the Q4000 (well completions) and the Intrepid (DP-2 capability and a
400-ton crane). The Q4000 has recently been completed, and both vessels are
expected to be working in the second quarter of 2002. When all of our DP vessels
begin work, we will have seven world class vessels permanently deployed in the
Gulf of Mexico.

With the acquisition of our new subsidiary, Canyon, we have increased our
operated ROV and trenching fleet to 26. Our new subsidiary's 18 ROVs are
designed for offshore construction (rather than drilling rig support) and its
management team adds industry experience in a setting where our vessels can add
value in support of its ROVs. As marine construction support in the Gulf of
Mexico moves to deeper waters, ROV systems will play an increasingly important
role. Canyon currently owns 18 ROV systems and operates seven others in three
regions: United States (13), Southeast Asia (8), and the North Sea (4). Canyon's
assets will

8

help to assure our customers of vessel availability and schedule flexibility to
meet the technological challenges of Deepwater construction developments in the
Gulf and internationally.

With its experienced personnel, our Well Operations Group is intended to
support downhole operations of the Uncle John and Q4000. Both vessels provide
cost-effective alternatives for Deepwater operations. This business line
involves drilling support (which includes pre-setting casings, setting trees and
commissioning wells), life-of-field services (which include well intervention),
decommissioning and abandonment. Previously there were few cost-effective
solutions for subsea well operations to troubleshoot or enhance production,
shift zones or perform recompletions, as most all of such work has been done
from drill rigs.

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

- FMC Corp. -- Well intervention hardware and risers

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

- Horizon Offshore, Inc. -- Small diameter reeled pipelay equipment

- Schlumberger Limited -- Deepwater downhole services

- Shell Offshore, Inc. -- Vessels for well intervention

While the DP market remained soft, the significant increase in utilization
(87% versus 56% a year ago) reflects improved market share and an expansion in
the scope of GOM deepwater installations. Major projects in 2001 were:

Shelf Contracting

In water depths up to 1,000 feet (the OCS), we perform traditional subsea
services including air and saturation diving in support of marine construction
activities. Fifteen of our vessels perform traditional subsea services, and six
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.

Aquatica delivers our services in the shallow water market (from the beach
to 300 fsw). In March 2001, Aquatica acquired substantially all of the four
vessels and business of Professional Divers and doubled the size of our DSV
fleet. We also perform numerous projects on the OCS in an alliance with Horizon
Offshore, Inc. In the late 1980's we demonstrated that pipelay operations would
be much more effective if the expensive barge spreads simply laid the pipe,
allowing our DSVs to follow along and perform the more time-consuming task of
commissioning the line. Principal features of the Alliance are that we have the
exclusive right to provide DSV services behind Horizon pipelay barges while
Horizon supplies pipelay, derrick barge and heavy lift capacity to Cal Dive. The
recent expansion of the Alliance also resulted in our providing the diving
personnel working from Horizon barges, a service Horizon handled internally last
year. Our interaction with Horizon is multi-faceted, including operations in
addition to those that flow from the formal alliance to provide services on the
OCS. For example, much of our work in Mexican waters has been subcontracted from
Horizon.

9

Since 1989, we have undertaken a wide variety of decommissioning
assignments, mostly on a turnkey basis. A recently revised study by the MMS
estimates that the total cost of the GOM abandonment market is $8.0 billion. Cal
Dive has established a leading position in the removal of smaller structures,
such as caissons and well protectors, which represent 52% of the structures in
the Gulf.

PRODUCTION PARTNERING

We formed ERT in 1992 to exploit a market opportunity to provide a more
efficient solution to offshore abandonment. Its business plan has evolved into
the concept of Production Partnering, the business segment that differentiates
us from our competitors. Production Partnering offers customers the option of
selling mature offshore fields and also expands our off-season salvage and
decommissioning activity to enable us to support full field production
development projects. The business advantages of our production business are
fourfold. First, the financial smoothing of oil and gas revenues counteracts the
lumpiness and the extreme volatility in the revenues and income which most
offshore construction companies have reported in the past three years. In
periods of excess capacity such as 2001, we have the flexibility to stay out of
the competitive bid market, focusing instead upon negotiated contracts. Third,
our oil and gas operations generate significant cash flow that has funded
construction of assets such as the Q4000, Intrepid and Eclipse while enabling us
to add technical talent to support our expansion into the new Deepwater
frontier. Finally, the primary objective of each CDI investment 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 and lease operations. ERT makes its money in three ways:
lowering salvage costs by using our assets, operating the field more cost
effectively and extending reservoir life through well exploitation operations.
The periodic collapses of commodity prices in the last few years removed some of
the small companies which buy mature properties. In the past two years, however,
two competitors have captured significant market share. In the face of this
competition, our disciplined strategy resulted in completing only three small
mature property acquisitions in 2001, as high commodity prices made such
purchases difficult. Rather than chase the upcycle and pay too much for
properties, our emphasis turned internally to extracting more value from the
existing property base. ERT designed and executed a significant well enhancement
program that resulted in adding 8.2 BCFe to proved reserves at a cost of $1.06
per Mcf.

There are 142 announced commercial discoveries in the deepwater GOM that
have yet to be brought into production. Many of these are smaller reservoirs
that standing alone cannot justify the economics of a host production facility.
As a result we expect that the Deepwater GOM will be developed in a hub and
satellite field concept that resembles the approach the airline industry has
used with regional hub locations. We see significant opportunities as this
occurs. For example, Gunnison, our first Deepwater field development project, is
a hub location where we will provide infrastructure and tie-back marine
construction services. At the Marco Polo field, although final agreements and
financing have not been agreed, our 50% ownership in the production facility
would allow Cal Dive to realize a transmission return. In addition we seek to
assist with the installation of the TLP and then work to develop the surrounding
acreage which can be tied back to the platform by CDI construction vessels.

CUSTOMERS

Our customers include major and independent natural gas and oil 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: 2001-Horizon
Offshore, Inc. (18%), Enron Corporation (10%); 2000-Enron Corporation (13%); and
1999-EEX Corporation (13%). We estimate that in 2001 we provided subsea services
to over 211 customers. Our projects are typically of short duration and are

10

generally awarded shortly before mobilization. Accordingly, we believe backlog
is not a meaningful indicator of future business results.

COMPETITION

The subsea services industry is highly competitive. While price is a
factor, the ability to utilize specialized vessels, to attract and retain
skilled personnel and to 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
Global Industries Ltd., Oceaneering International, Inc., Stolt Offshore S.A.,
and Technip-Coflexip. Other foreign-based subsea contractors, including DSND
Ltd., Rockwater, Ltd. and Saipem S.p.A., may periodically perform services in
the Gulf.

ERT encounters significant competition for the acquisition of mature
natural gas and oil properties. Two such competitors are Tetra Technologies,
Inc. and Offshore Specialty Fabricators. Our ability to acquire additional
properties depends upon our ability to evaluate and select suitable properties
and to consummate transactions in a highly competitive environment. Many of our
competitors are well-established companies with substantially larger operating
staffs and greater capital resources.

TRAINING, SAFETY AND QUALITY ASSURANCE

As work levels increase on the OCS, safety, our single most important
objective, will be even more important because the projects in these water
depths are more personnel-intensive. Over 35 years Cal Dive has continuously
upgraded and revitalized so that environment, health and safety (EHS) at work
are embraced as core business values. Our Executive EHS Steering Committee,
chaired by the President and Vice Presidents, meets monthly to decide on
strategy and action plans for improvements. Our behavioral safety process (BSP)
empowers employees to take control of their own safety at work using proven
techniques of employees observing each other for correct and safe behavior.
During 2001, we introduced a company-wide program to enhance the BSP and
training that makes safety a constant focus of awareness through open
communication with all offshore and yard employees. Management believes that our
safety programs are among the best in the industry.

GOVERNMENT REGULATION

Many aspects of the offshore marine construction industry are subject to
extensive governmental regulation. We are subject to the jurisdiction of the
Coast Guard, the Environmental Protection Agency, MMS and the U.S. Customs
Service, as well as private industry organizations such as the American Bureau
of Shipping.

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 natural gas and oil
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 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 $500,000 per producing lease. We currently
11

have bonded our offshore leases as required by the MMS. Under certain
circumstances, the MMS has the authority to suspend or terminate operations on
federal leases. Any such suspensions or terminations of our operations could
have a material adverse effect on our financial condition and results of
operations.

We acquire production rights to offshore mature natural gas and oil
properties under federal natural gas and oil 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 (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. In December 1999,
the MMS issued regulations that would allow it to expel unsafe operators from
existing OCS platforms and bar them from obtaining future leases.

Under the OCSLA, MMS also administers oil and gas leases and establishes
regulations that set the basis for royalties on oil and gas produced from the
leases. The MMS amends these regulations from time to time. For example, on
March 15, 2000, the MMS issued a final rule governing the calculation of
royalties and the valuation of crude oil produced from federal leases. The rule
modifies the valuation procedures for both arm's length and non-arm's length
crude oil transactions to decrease reliance on oil posted prices and assign a
value to crude oil that better reflects market value. The rule has been
challenged by two industry trade associations and is currently under judicial
review in the United States District Court for the District of Columbia. In
addition, the MMS recently issued a final rule amending its regulations
regarding costs for natural gas transportation which are deductible for royalty
valuation purposes when natural gas is sold off-lease. Among other matters, for
purposes of computing royalty owed, the rule disallows as deductions certain
costs, such as aggregator/marketer fees and transportation imbalance charges and
associated penalties. A United States District Court, however, enjoined
substantial portions of this rule on March 28, 2000. The United States appealed
the district court decision and the case is pending before the Court of Appeals
for the District of Columbia Circuit.

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

Sales of natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation remain
subject to extensive federal and state regulation. Several major regulatory
changes have been implemented by Congress and the FERC from 1985 to the present
that affect the economics of natural gas production, transportation and sales.
In addition, the FERC continues to promulgate revisions to various aspects of
the rules and regulations affecting those segments of the natural gas 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. In addition,
many aspects of these regulatory developments have not become final but are
still pending judicial and FERC final decisions.

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

12

Additional proposals and proceedings before various federal and state
regulatory agencies and the courts could affect the natural gas and oil
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 federal, state and local 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.

The Oil Pollution Act of 1990, as amended (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 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
13

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 which 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 supply boats 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 natural gas and oil, 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 the 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
(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.

Management believes 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 March 26, 2002, we had
835 employees, 230 of which were salaried. As of that date we also utilized
approximately 111 non-U.S. citizens to crew our foreign flag vessels under a
crewing contract with C-MAR Services (UK), Ltd. of Aberdeen, Scotland. None of
our employees belong to a union or are employed pursuant to any collective
bargaining agreement or any similar arrangement. Management believes that our
relationship with our employees and foreign crew members is good.

14

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 on 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:

- Worldwide economic activity

- Coordination by the Organization of Petroleum Exporting Countries (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 regulation

- Tax policies

The level of offshore development and production activity did not increase
materially in 2001 despite high commodity prices in the first half of the year.
We cannot assure you that activity levels will increase anytime soon. A
sustained period of low drilling and production activity or a return of low
hydrocarbon prices would likely have a material adverse effect on our financial
position and results of operations.

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

Marine construction involves a high degree of operational risk. Hazards,
such as vessels sinking, grounding, colliding and sustaining damage from severe
weather conditions, are inherent in marine operations. These hazards can cause
personal injury or loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.
Damage arising from such occurrences may result in lawsuits asserting large
claims. We maintain such insurance protection as we deem prudent, including
Jones Act employee coverage (the maritime equivalent of workers' compensation)
and hull

15

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 construction activity moves into deeper water in the
Gulf, construction projects tend to be larger and more complex than shallow
water projects. As a result, our revenues and profits are increasingly dependent
on our larger vessels. While the loss of the Balmoral Sea was covered by
insurance, the current insurance on our vessels (in some cases, in amounts
approximating book value, which is less than replacement value) against property
loss due to a catastrophic marine disaster, mechanical failure or collision 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 lost
any of our large vessels.

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

Marine operations conducted in the Gulf 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, and
we 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, the results of any one quarter
are not necessarily indicative of annual results or continuing trends.

IF WE BID TOO LOW ON A TURNKEY CONTRACT WE SUFFER THE 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 charged 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 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 NATURAL GAS AND OIL RESERVES, FUTURE CASH FLOWS AND ABANDONMENT
COSTS MAY BE SIGNIFICANTLY INCORRECT.

This Annual Report contains estimates of our proved natural gas and oil
reserves and the estimated future net cash flows therefrom based upon reports
prepared for the years ended December 31, 2001, 2000 and 1999. Excluding the
Gunnison reserves for the year ended December 31, 2001, these reports were
reviewed by Miller and Lents, Ltd. This report relies upon various assumptions,
including assumptions required by the Securities and Exchange Commission as to
natural gas and oil prices, drilling and operating expenses, capital
expenditures, abandonment costs, taxes and availability of funds. The process of
estimating natural gas and oil 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 natural gas and oil 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 Form 10-K is the current market value of our
estimated natural gas and oil reserves. In accordance with Securities and
Exchange Commission requirements, we base the estimated discounted future net
cash flows from our proved reserves on prices and costs on the date of the
estimate. Actual future prices and costs may differ materially from those used
in the net present value estimate. In addition, if costs of abandonment are
materially greater than our estimates, they could have an adverse effect on
earnings. Proved reserves at December 31, 2001 also included the initial
reserves assigned to our ownership position in Gunnison. Since we do not own the
seismic data for the three fields this figure represents 15% of the reserves
reported by the operator, Kerr-McGee Oil & Gas Corporation.

16

THE GUNNISON PROSPECT MAY NOT RESULT IN THE EXPECTED CASH FLOWS OR SUBSEA ASSET
UTILIZATION WE ANTICIPATE AND COULD INVOLVE SIGNIFICANT FUTURE CAPITAL OUTLAYS.

The Gunnison prospect is subject to a number of assumptions and
uncertainties, including estimates of the capital outlays necessary to develop
the prospect and the cash flows that we may ultimately derive. We cannot assure
you that we will be able to fund all required capital outlays or that these
outlays will be profitable. Moreover, although our working interest entitles us
to participate in field development and planning and to collaborate with the
other working interest owners in executing subsea construction work, the extent
of utilization of our subsea assets for such work has not been determined.

EXPECTED CASH FLOWS FROM THE Q4000 AND INTREPID UPON COMPLETION MAY NOT BE
IMMEDIATE OR AS HIGH AS EXPECTED.

These vessels are scheduled to be placed into service in the second quarter
of 2002. Additionally delays could also have a material adverse effect on
expected utilization for these vessels and our future revenues and cash flows.
We will not receive any material increase in revenue or cash flow from either
vessel until placed in service. Furthermore, we cannot assure you of customer
demand for the Q4000 as that vessel targets the well operations market and, as a
result, our future cash flows may be adversely affected. While elements of this
vessel design have been patented, new vessels from third parties may also enter
the market in the coming years and compete with us for contracts.

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

Our natural gas and oil operations are subject to the usual risks incident
to the operation of natural gas and oil wells, including, but not limited to,
uncontrollable flows of oil, natural 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. In accordance with industry practice, we maintain insurance against some,
but not all, of the risks described above.

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

The business in which we operate is highly competitive. Several of our
competitors are substantially larger and have greater financial and other
resources than we have. If other companies relocate or acquire vessels for
operations in the Gulf, 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, ASSIMILATE AND RETAIN OTHER HIGHLY QUALIFIED PERSONNEL IN THE FUTURE,
COULD DISRUPT OUR OPERATIONS AND ADVERSELY AFFECT OUR FINANCIAL RESULTS.

The industry has lost a significant number of experienced subsea people
over the years due to, among other reasons, the decrease 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
employ 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.

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

Our subsea construction, inspection, maintenance and decommissioning
operations and our natural gas and oil production from offshore properties
(including decommissioning of such properties) are subject to and affected by
various types of government regulation, including numerous federal, state and
local environmental
17

protection laws and regulations. These laws and regulations are becoming
increasingly complex, stringent and expensive. We cannot assure you that
continued compliance with existing or future laws or regulations will not
adversely affect our operations. Significant fines and penalties may be imposed
for noncompliance.

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

Our Board of Directors has the authority, without any action by our
shareholders, to fix the rights and preferences on up to 5,000,000 shares of
undesignated preferred stock, including dividend, liquidation and voting rights.
In addition, our Bylaws 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 which 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 and operate a fleet of 23 vessels and 19 ROVs. Management believes
that the GOM market requires specially designed and/or equipped vessels to
competitively deliver subsea construction services. Seven of our vessels have DP
capabilities specifically designed to respond to the Deepwater market
requirements. Six of our vessels have the capability to provide saturation
diving services. Recent developments in our fleet include:

Q4000: In September 1999, we began construction of our newest
Deepwater MSV, the Q4000. The vessel has been constructed at an estimated
cost of $180 million and incorporates our latest semi-submersible
technologies, including various patented elements such as the absence of
lower hull cross bracing. Variable deck load of 3,400 metric tons upgraded
well completions capability make the vessel particularly well suited for
large offshore construction projects in the Ultra-Deepwater. Its
Huisman-Itrec multi-purpose tower has an open face which allows free access
from three sides, an advantage for a construction and intervention vessel.
Another important feature of the Q4000 will be the new intervention riser
system we are developing and jointly funding with FMC Corporation. This
system will be the first in the industry rated for working pressures to
15,000 pounds per square inch in 10,000 fsw. The Q4000 will be in service
in the second quarter of 2002.

Intrepid: CDI is currently in the final stages of converting the
former Sea Sorceress. While we refer to this as a conversion, the work
constitutes the construction of new DP-2 pipelay vessel into the hull of
our ice class vessel acquired three years ago. She will offer customers a
construction vessel capable of carrying an 8,000 metric ton deckload. We
expect her to be available for work the second quarter of 2002.

Mystic Viking: The DPDSV is 240 feet long and 52 feet wide. Her class
is similar to the Witch Queen with DP-2 redundancy, 500 ton load, 2 cranes
and a 12 foot x 12 foot moonpool. This vessel was acquired in May of 2002.

Eclipse: This large DPDSV is 370 feet long and 67 feet wide. She has
recently been outfitted with her original marine construction features by
installing a SAT diving system, restoring the ballast system and upgrading
to DP-2. The Eclipse began work in March 2002.

Northern Canyon: Canyon Offshore will take delivery of this purpose
built, 270 foot state-of-the-art ROV support vessel which will be deployed
initially in the North Sea.

Robotics: To enable us to control critical path equipment involved in
our deepwater projects, we acquired Canyon at the end of 2001. Canyon
Offshore currently owns 18 ROVs and operates 7 trenching

18

systems. In 2001, Canyon introduced the next-generation work-class ROV, the
Quest. Advantages of the Quest include: electric instead of hydraulic
systems, 50% smaller footprint, fewer moving parts (i.e. lower operating
costs), a dynamic positioning system and improved depth rating. The average
age of the Canyon ROV fleet is approximately two years.

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 ABS, Det Norske Veritas ("DNV") and the Coast Guard. 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.

19

(2) In March 2001, CDI acquired substantially all of the assets of Professional
Divers of New Orleans, Inc. including the Mr. Sonny (a 165-foot four-point
moored DSV), three utility vessels and associated diving equipment including
two saturation diving systems.

(3) This leased vessel is under construction and should be available June 15,
2002.

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 which management believes 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. All of our
vessels are subject to ship mortgages to secure our $60.0 million revolving
credit facility with Fleet Credit Corporation, except the Northern Canyon (which
will be leased) and the Q4000 (which is subject to liens to secure the MARAD
financing).

SUMMARY OF NATURAL GAS AND OIL RESERVE DATA

The table below sets forth information, as of December 31, 2001, with
respect to estimates of net proved reserves and the present value of estimated
future net cash flows at such date for ERT (not including Gunnison), prepared by
Company engineers in accordance with guidelines established by the Securities
and Exchange Commission. Our estimates have been reviewed by Miller and Lents,
Ltd., independent petroleum engineers.

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

(1) 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, 2001, ERT owned (not
including Gunnison) an interest in 122 gross (102 net) natural gas wells and
104 gross (79 net) oil wells located in federal offshore waters in the Gulf
of Mexico.

(2) Total proven reserves at year-end grew to 100 BCFe with initial reserves of
76.5 BCFe assigned to our ownership position in Gunnison. This figure
represents 15% of the reserves reported by the operator, Kerr-McGee Oil &
Gas Corporation, at December 31, 2001.

FACILITIES

Our headquarters is 400 N. Sam Houston Parkway E., Houston, Texas. Our
primary subsea and marine services operations are based in Morgan City,
Louisiana. All of our facilities are leased.

20

PROPERTY AND FACILITIES SUMMARY

We also have sales offices in Lafayette and Harvey, Louisiana.

ITEM 3. LEGAL PROCEEDINGS

INSURANCE AND LITIGATION

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

We are involved in various legal proceedings, primarily involving claims
for personal injury under the General Maritime Laws of the United States and the
Jones Act as a result of alleged negligence. In addition, we from time to time
incur other claims, such as contract disputes, in the normal course of business.
In that regard, we entered into a subcontract with Seacore Marine Contractors
Limited to provide the Sea Sorceress for subsea excavation in Canada. Seacore
was in turn contracted by Coflexip Stena Offshore Newfoundland Limited, a
subsidiary of Coflexip (CSO Nfl), as representative of the consortium of
companies contracted to perform services on the project. Due to difficulties
with respect to the sea states and soil conditions the contract was terminated.
Cal Dive provided Seacore a performance bond of $5 million with respect to the
subcontract. No call has been made on this bond. Although CSO Nfl has alleged
that the Sea Sorceress was unable to adequately perform the excavation work
required under the subcontract, Seacore and we believe the contract was
wrongfully terminated and are vigorously defending this claim and seeking
damages in arbitration. In another commercial dispute, EEX Corporation sued us
and others alleging breach of fiduciary duty by a former EEX employee and
damages resulting from certain construction and property acquisition agreements.
We have responded alleging EEX Corporation breached various provisions of the
same contracts and are seeking a declaratory judgment that the defendants are
not liable. Although such litigation has the potential of significant liability,
we believe that the outcomes of all such proceedings are not likely to have a
material adverse effect on our consolidated financial position, results of
operations or cash flows.

21

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

None.

ITEM (UNNUMBERED). EXECUTIVE OFFICERS OF THE COMPANY

DIRECTORS, EXECUTIVE OFFICERS AND KEY EMPLOYEES

The executive officers and directors of Cal Dive are as follows:

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

(1) Member of Compensation Committee

(2) Member of Audit Committee

(3) Member of Nominating Committee

(4) Member of Executive Committee

Our Bylaws provide for the Board of Directors to be divided into three
classes of directors, with each class to be as nearly equal in number of
directors as possible, serving staggered three-year terms. The terms of the
Class III directors, Gordon Ahalt and Martin R. Ferron, expire in 2002. The
terms of the Class II directors, S. James Nelson, Jr. and William L. Transier,
expire in 2003. The terms of the Class I directors, Owen Kratz and Bernard
Duroc-Danner, expire in 2004. Each director serves until the end of his or her
term or until his or her successor is elected and qualified.

Owen Kratz is Chairman and Chief Executive Officer of Cal Dive
International, Inc. He was appointed Chairman in May 1998 and has served as the
Company's 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 the Company
in 1984 and has held various offshore positions, including saturation (SAT)
diving supervisor, and has had management responsibility for client relations,
marketing and estimating. From 1982 to 1983, Mr. Kratz was the owner of an
independent marine construction company operating in the Bay of Campeche. Prior
to 1982, he was a superintendent for Santa Fe and various international diving
companies, and a saturation diver in the North Sea.

Martin R. Ferron has served on our Board of Directors since September 1998.
Mr. Ferron became President in February 1999 and has served as Chief Operating
Officer since January 1998. Mr. Ferron has 20 years of experience in the
oilfield industry, including seven in senior management positions with the
international operations of McDermott Marine Construction and Oceaneering
International Services, Limited. Mr. Ferron has a civil engineering degree, a
master's degree in marine technology, an MBA and is a chartered civil engineer.

22

S. James Nelson, Jr. is Vice Chairman and has been a Director of the
Company since 1990. Prior to October 2000, he was Executive Vice President and
Chief Financial Officer. From 1985 to 1988, Mr. Nelson was the Senior Vice
President and Chief Financial Officer of Diversified Energies, Inc., the former
parent of the Company, at which time he had corporate responsibility for the
Company. From 1980 to 1985, Mr. Nelson served as Chief Financial Officer of
Apache Corporation, an oil and gas exploration and production company. From 1966
to 1980, Mr. Nelson was employed with Arthur Andersen & Co., and, from 1976 to
1980, he was a partner serving on the firm's worldwide oil and gas industry
team. Mr. Nelson received an undergraduate degree from Holy Cross College (B.S.)
and an MBA from Harvard University; he is also a Certified Public Accountant.

Andrew C. Becher has served as Senior Vice President, General Counsel of
Cal Dive since January 1996 and became Corporate Secretary in 1998. Mr. Becher
served as outside general counsel for Cal Dive from 1990 to 1996, while a
partner with the national law firm of Robins, Kaplan, Miller & Ciresi of
Minneapolis. From 1987 to 1990, Mr. Becher was Senior Vice President -- Mergers
and Acquisitions of Dain Rauscher, Inc., an investment banking firm. From 1976
to 1987, he was a partner specializing in mergers and acquisitions with the law
firm of Briggs and Morgan of Minneapolis.

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 treasury, accounting, information technology,
tax, administration and corporate planning functions. He joined the Company in
May 1997, as Vice President -- Finance and Chief Accounting Officer. From 1988
through 1997 he was with Arthur Andersen LLP, lastly as an Experience 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.

Michael V. Ambrose is Senior Vice President -- Deepwater Contracting. His
previous experience includes worldwide operations manager for McDermott
Underwater Services, Inc. (MUS) from 1994 to 1997, and general manager of
operations for Offshore Petroleum Divers (OPD) from 1993 to 1994. Mr. Ambrose's
international experience was obtained from 1991 to 1993, while serving as
operations manager and setting up offices in Southeast Asia and India for OPD's
international managerial expansion. Mr. Ambrose served in Vietnam from 1965 to
1969 as a member of the United States Navy SEAL Team I.

Gordon F. Ahalt has served on our Board of Directors since July 1990 and
has extensive experience in the oil and gas industry. Since 1982, Mr. Ahalt has
been President of GFA, Inc., a petroleum industry management and financial
consulting firm. From 1977 to 1980, he was President of the International Energy
Bank, London, England. From 1980 to 1982, he served as Senior Vice President and
Chief Financial Officer of Ashland Oil Company. Previously, Mr. Ahalt spent a
number of years in executive positions with Chase Manhattan Bank. Mr. Ahalt
serves as a director of The Houston Exploration Co., the Bancroft & Elsworth
Convertible Funds and other investment funds.

Bernard J. Duroc-Danner has served on our Board of Directors since February
1999. Mr. Duroc-Danner is the Chairman, CEO and President of Weatherford
International, Inc., an oilfield service company. Mr. Duroc-Danner also serves
as Chairman of the Board of Grant Prideco and as a director of Parker Drilling
Company, a provider of contract drilling services and Universal Compression, a
provider of a rental, sales, operations, maintenance and fabrication services
and products to the domestic and international natural gas industry. Mr.
Duroc-Danner holds a Ph.D in economics from the Wharton School (University of
Pennsylvania).

William Transier has served on our Board of Directors since October 2000.
He is Executive Vice President and Chief Financial Officer for Ocean Energy,
Inc. and oversees treasury, investor relations, human resources, and marketing
and trading. He assumed his current position in 1999 following the merger of
Ocean Energy and Seagull Energy Corporation. Previously, Mr. Transier served as
Executive Vice President and Chief Financial Officer for Seagull and in the
audit department of KPMG LLP. Mr. Transier received an undergraduate degree from
the University of Texas and a master's in business administration from Regis
University. He is a director of Metals USA.

23

PART II

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

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

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

* The stock split 2 for 1 effective November 13, 2000. As of March 20, 2002,
there were an estimated 3,971 beneficial holders of our common stock.

DIVIDEND POLICY

We have never 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. Certain
of our current financing arrangements restrict the payment of cash dividends
under certain circumstances.

ITEM 6. SELECTED FINANCIAL DATA

The financial data presented below for each of the five years ended
December 31, 2001, 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).

24

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

OVERVIEW

Natural gas and oil prices, the offshore mobile rig count, and Deepwater
construction activity are three of the primary indicators management uses to
forecast the future performance of our business. Our construction services
generally follow successful drilling activities by six to eighteen months on the
OCS and twelve months or longer in the Deepwater arena. The level of drilling
activity is related to both short- and long-term trends in natural gas and oil
prices. Commodity prices declined significantly in the last half of 1998 and
early 1999, resulting in the offshore mobile rig utilization rates dropping to
approximately 70% in contrast to almost full utilization in 1997 and the first
half of 1998. This trend began reversing in the second quarter of 1999 as oil
prices reached their highest levels since the Gulf War and in early 2001 natural
gas prices reached $10.00 per thousand cubic feet (Mcf), pushing the offshore
mobile rig utilization rates back to virtually full utilization. However, a
slowing world economy and record levels of natural gas in storage drove oil and
gas prices down throughout 2001 with natural gas plunging to $2.00 per Mcf by
the end of the year. Our primary leading indicator, the number of offshore
mobile rigs contracted, is currently running at around 120 rigs employed in the
Gulf of Mexico, compared to 180 last year at this time. The Deepwater GOM is
principally an oil play with the size of the reservoirs resulting in significant
lead times to first production. We are currently tracking 30 fields that will
come into our service market, completion and production, principally in the
years 2003 and 2004. We have aggressively moved to assemble a world-class fleet
of seven DP vessels as we do not believe that there will be enough marine
construction capacity to handle this demand.

Product prices impact our natural gas and oil operations in several
respects. We seek to acquire producing natural gas and oil properties that are
generally in the later stages of their economic life. The potential abandonment
liability is 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, such as in 2000 and the first
half of 2001. In contrast, lower natural gas prices, as experienced in early
1999 and late 2001, typically contribute to lower operating results for ERT and
a general increase in the number of mature properties available, as occurred
during those periods. We have expanded the scope of our gas and oil operations
by taking a working interest in Gunnison, a Deepwater development of Kerr-McGee
Oil & Gas Corporation which has encountered significant reserves. We are also
expanding our Deepwater Hub strategy by agreeing to participate in the ownership
of the Marco Polo production facility.

Vessel utilization is historically lower during the first quarter due to
winter weather conditions in the Gulf. Accordingly, we plan our drydock
inspections and other routine and preventive maintenance programs during this
period. During the first quarter, a substantial number of our customers finalize
capital budgets and solicit bids for construction projects. The bid and award
process during the first two quarters typically leads to the commencement of
construction activities during the second and third quarters. As a result, we
have historically generated more than 50% (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. Our salvage barge, which has a
shallow draft, is particularly sensitive to adverse weather conditions, and its
utilization rate tends to be lower during such periods. To minimize the impact
of weather conditions on our operations and financial condition, we began
operating DP vessels and expanded into the acquisition of oil and gas
properties. The unique station-keeping ability offered by DP enables these
vessels to operate throughout the winter months and in rough seas. Operation of
natural gas and oil 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.

CRITICAL ACCOUNTING POLICIES

The results of operations and financial condition of the Company, as
reflected in the accompanying financial statements and related footnotes, are
subject to management's evaluation and interpretation of
25

business conditions, changing capital market conditions and other factors which
could affect the ongoing viability of the Company's business segments and/or its
customers. Management believes the most critical accounting policies in this
regard are the estimation of revenue allowance on gross amounts billed and
evaluation of recoverability of property and equipment and goodwill balances.
These issues require management to make judgments that are subjective in nature,
however, management is able to consider and assess a significant amount of
historical data and current market data in arriving at reasonable estimates.
Another area which requires management to make subjective judgments is that of
revenue recognition. CDI's 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. 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. 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.

ERT acquisitions of producing offshore properties are recorded at the value
exchanged at closing together with an estimate of its proportionate share of the
undiscounted 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 Company
follows the successful efforts method of accounting for its interests in natural
gas and oil 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.

NEW ACCOUNTING PRONOUNCEMENTS

In July 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 141, Business
Combinations, which supersedes Accounting Principles Board (APB) Opinion No. 16,
Business Combinations. SFAS 141 eliminates the pooling-of-interests method of
accounting for business combinations and modifies the application of the
purchase accounting method. The provisions of SFAS 141 were effective for
transactions accounted for using the purchase method completed after June 30,
2001. The Company completed no business combination between June 30, 2001 and
December 31, 2001. The Company did acquire 85% of Canyon Offshore, Inc. in
January 2002 and accounted for the acquisition using the purchase method in
accordance with SFAS 141. See further discussion below.

In July 2001, the FASB also issued SFAS No. 142, Goodwill and Intangible
Assets, which supersedes APB Opinion No. 17, Intangible Assets. SFAS 142
eliminates the current requirement to amortize goodwill and indefinite-lived
intangible assets, addresses the amortization of intangible assets with a
defined life and addresses the impairment testing and recognition for goodwill
and intangible assets. SFAS 142, which is effective for 2002, will apply to
goodwill and intangible assets arising from transactions completed before and
after the statement's effective date. We believe adoption of this standard will
have an immaterial effect on CDI's financial position and results of operations.

In July 2001, the FASB released SFAS No. 143, Accounting for Asset
Retirement Obligations, which is required to be adopted by the Company no later
than January 1, 2003. SFAS No. 143 addresses the financial accounting and
reporting obligations and retirement costs related to the retirement of tangible
long-lived assets. The Company is currently reviewing the provisions of SFAS No.
143 to determine the standard's impact, if any, on its financial statements upon
adoption. Among other things SFAS No. 143 will require oil and gas companies to
reflect decommissioning liabilities on the face of the balance sheet, something
ERT has done since inception on an undiscounted basis.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets, which is effective for the Company beginning
January 1, 2002. SFAS No. 144 supersedes SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and
the accounting and reporting provisions relating to the disposal of a segment of
a business of APB Opinion

26

No. 30. The Company believes that the adoption of SFAS No. 144 will not have a
material impact on its financial position or results of operations.

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) Average of the monthly Henry Hub cash prices per Mcf, as reported in Natural
Gas Week.

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

(3) Source: Offshore Data Services; installation and removal of platforms with
two or more piles in the Gulf.

(4) Average vessel utilization rate is calculated by dividing the total number
of days the vessels in this category generated revenues by the total number
of days in each quarter (excluding Aquatica vessels in 1999). During the
second quarter of 1999, the Uncle John spent 30 days in drydock undergoing
thruster work and inspections. During the second quarter of 2000, the Uncle
John spent 47 days in drydock for engine replacement and inspections and the
Witch Queen spent 41 days in drydock undergoing regulatory inspections.
During the third quarter of 2000, these vessels were out for a combined 105
days for the same reasons.

ITEM 7. RESULTS OF OPERATIONS

COMPARISON OF YEAR ENDED DECEMBER 31, 2001 AND 2000

Revenues. During the year ended December 31, 2001, the Company's revenues
increased 25% to $227.1 million compared to $181.0 million for the year ended
December 31, 2000 with the Subsea and Salvage segment contributing all of the
increase. Aquatica revenues increased 80% to $37.0 million for 2001 from $20.6
million in the prior year due, in part, to added capacity as a result of our
acquisition of Professional Divers of New Orleans, Inc. in February 2001 and
improved OCS activity. Revenues generated from our DP fleet increased 54% to
$79.3 million during 2001 compared to $51.4 million in 2000 due mainly to vessel
utilization improving from 56% during 2000 to 87%. This increased utility
reflects improved CDI market share, an expansion in the scope of Deepwater
services provided and expansion into other regions (Mexico and Trinidad).

Natural Gas and Oil Production revenue for the year ended December 31, 2001
decreased 10% to $63.4 million from $70.8 million during the prior year due to a
10% decrease in production from 15.5 Bcfe in 2000 compared to 13.9 Bcfe during
2001. ERT received an average of $4.44 per Mcf for natural gas and $24.54 per
Bbl for oil during 2001 compared to $4.04 per Mcf and $28.91 per Bbl in 2000.
Oil and condensate represented 30% of ERT's revenues in 2001 versus 27% in 2000.

Gross Profit. Gross profit of $66.9 million for the year ended December
31, 2001 was 21% better than the $55.4 million gross profit recorded in the
prior year with Subsea and Salvage contracting gross profit
27

providing all of the increase and offsetting a $9.1 million decline in Natural
Gas & Oil Production gross profit. Subsea and Salvage margins improved from 15%
for the year ended December 31, 2000 to 22% during the year ended December 31,
2001 due mainly to the increase in utilization due to increased marine
construction activity, even though we earned only 5% margins on $15 million of
Nansen/Boomvang volume that was mostly pass-through revenue.

Natural Gas and Oil Production gross profit decreased $9.1 million from
$39.3 million in the year ended December 31, 2000 to $30.2 million for the year
ended December 31, 2001 due mainly to the aforementioned 10% decline in
production, higher amortization rates in 2001 than 2000 and $1.0 million of
accounts receivable exposure related to the Enron bankruptcy.

Selling and Administrative Expenses. Selling and administrative expenses
were $21.3 million in 2001, which is relatively flat (3% increase) with the
$20.8 million incurred during 2000. Given the increased revenues, this tight
cost control provided a two point margin improvement (i.e., 9% margin for the
year ended December 31, 2001 compared to 11% for the year ended December 31,
2000).

Net Interest (Income) Expense and Other. The Company reported net interest
expense and other of $1.3 million for the year ended December 31, 2001 in
contrast to $554,000 for the prior year as average cash balances (net of MARAD
financing) declined during 2001 as compared to 2000 due mainly to costs
associated with construction of the Q4000 and the Intrepid conversion.

Income Taxes. Income taxes increased to $15.5 million for the year ended
December 31, 2001, compared to $11.6 million in the prior year due to increased
profitability. Federal income taxes were provided at the statutory rate of 35%
in 2001. However, our deduction of Q4000 construction costs as Research and
Development expenditures for federal tax purposes resulted in CDI paying no
federal income taxes in 2001 and 2000. Since the deduction of Q4000 construction
costs affects financial and taxable income in different years, the entire 2001
and 2000 provisions for federal taxes were reflected as deferred income taxes.
In addition, the balance sheet includes a $10.0 million income tax receivable as
of December 31, 2000 which reflects our amending prior year tax returns to
reflect the deduction of such costs (these tax refunds were received in January
2001).

Net Income. Net income of $28.9 million for the year ended December 31,
2001 was $5.6 million, or 24%, more than 2000 as a result of factors described
above.

COMPARISON OF YEAR ENDED DECEMBER 31, 2000 AND 1999

Revenues. During the year ended December 31, 2000, our revenues increased
12% to $181.0 million compared to $161.0 million for the year ended December 31,
1999, with Natural Gas and Oil Production contributing all of the increase.
Revenue for Subsea and Salvage decreased from $128.4 million to $110.2 million.
Subsea and Salvage contracting revenues include almost $17.1 million of revenues
from the addition of the DP vessel Cal Dive Aker Dove and the acquisition of the
55% of Aquatica not previously owned.

Exclusive of these new assets, Subsea and Salvage contributed $35.3 million
less in 2000 than it did in 1999, due primarily to the weak GOM construction
market in 2000 and eight vessels being out of service during the first half of
2000 for a combined 416 days for U.S. Coast Guard (the Coast Guard or USCG) and
American Bureau of Shipping (ABS) inspections and two major DP vessels being out
of service a combined total of 105 days during the third quarter of 2000. This
compares to three vessels being out of service for a combined 113 days during
1999. In addition, the 2000 salvage market was slower than anticipated as
producers retained ownership to milk the last production out of mature fields
and to take advantage of the high commodity prices. As a result, revenues from
our barge operations (which include the subcontract of Horizon derrick and
pipelay barges) were only $12.5 million during 2000 or two-thirds of the prior
year. Margins also suffered as too many salvage contractors chased too little
work.

Natural Gas and Oil Production revenue for 2000 increased 118% to $70.8
million from $32.5 million during the prior year due to a 74% increase in
production from 8.9 Bcfe to 15.5 Bcfe. Production grew as a result of the
acquisition of interests in six offshore blocks from EEX Corporation during the
first quarter as
28

well as additional production derived from 1999 property acquisitions (involving
a total of 20 offshore blocks) and the 1999 well exploitation program. In
addition, we realized an average gas price of $4.03 per Mcf equivalent in 2000,
an increase of $1.68, or 71%, over 1999. Oil prices averaged over $29 per barrel
and represented 27% of gas and oil revenues in 2000.

Gross Profit. Gross profit of $55.4 million for 2000 was 49% better than
the $37.3 million gross profit recorded in the comparable prior year period due
mainly to the revenue improvement as well as an eight point improvement in
margins (31% in 2000 versus 23% in the prior year). Subsea and Salvage margins
declined from 20% for 1999 to 15% for 2000 due partly to the weak market and the
additional vessels out of service for regulatory inspections and upgrades. While
Aquatica margins remained at roughly the consolidated average of 30%, those of
the larger vessels that work from 300 feet out into the Deepwater declined by
seven percentage points from the prior year. The newly added Cal Dive Aker Dove
represented more than half of the year-over-year decline in the gross profit
generated by our DP fleet. The operating loss of this vessel was due to the low
level of utilization in 2000 and to the sale/leaseback structure whereby
financing cost was reported above the line as a charter cost.

Natural Gas and Oil Production gross profit increased $27.4 million from
$11.9 million in 1999 to $39.3 million for 2000 (and margins improved from 37%
to 55%) due to the aforementioned production and commodity pricing improvements.

Selling and Administrative Expenses. Selling and administrative expenses
were $20.8 million in 2000, a 57% increase over the $13.2 million incurred in
1999 due mainly to improved operating results for ERT, whose incentive plan
tracks its operating results ($3.1 million increase), and to the consolidation
of Aquatica ($1.4 million increase). The remainder of the increase is due to the
addition of personnel to the newly formed Well Operations Group to meet the
anticipated demand for our services in the Deepwater market.

Net Interest (Income) Expense and Other. We reported net interest expense
and other of $554,000 for 2000 in contrast to $849,000 of net interest income
for 1999 as average cash balances declined during 2000 as compared to 1999. This
decrease was due mainly to the Company's capital program (Q4000 vessel
construction) combined with the recording of goodwill amortization expense
beginning in August 1999 upon acquiring the 55% of Aquatica, Inc. that we did
not already own. Minority interest added back $866,000 in 2000 compared to
$109,000 reduction in 1999 due to the losses recorded in 2000 by the Cal Dive
Aker Dove, a vessel which was jointly owned with Aker Maritime.

Income Taxes. Income taxes increased to $11.6 million for 2000, compared
to $8.5 million in the prior year due to increased profitability. Federal income
taxes were provided at 34% in 2000, slightly below the statutory rate of 35%.

Net Income. Net income of $23.3 million for 2000 was $6.4 million, or 38%
more than 1999 as a result of factors described above. Diluted earnings per
share increased only 31% reflecting the additional shares issued to acquire
Aquatica in the third quarter of 1999 and the shares sold in conjunction with
the Secondary Offering (Green Shoe).

LIQUIDITY AND CAPITAL RESOURCES

The Company completed an initial public offering of common stock on July 7,
1997, with the net proceeds of approximately $39.5 million resulting in $15
million of cash on hand after paying off all debt outstanding. The following
three years internally generated cash flow funded approximately $164 million of
capital expenditures while enabling the Company to remain essentially debt free.
During the third quarter of 2000 we closed the long-term MARAD financing for
construction of the Q4000 and have drawn $99.5 million on this facility through
December 31, 2001. In January 2002, the Maritime Administration agreed to expand
the facility to $160 million to include the modifications to the vessel which
had been approved during 2001. Through December 31, 2001, we have funded over
$137 million of the newbuild vessel's $182 million budgeted construction costs.
Significant internally generated cash flow during 2001, coupled with the
collection of a $10 million tax refund enabled us to acquire the Mystic Viking
(a 240 foot DP vessel), the Eclipse (a 370 foot DP vessel) and Professional
Divers of New Orleans, Inc. (PDNO) while maintaining cash

29

balances of $37.1 million as of December 31, 2001. In January 2002, we acquired
approximately 85% of Canyon Offshore, Inc. for cash of $51 million, the
assumption of $5 million of net debt and 181,000 shares of CDI common stock
(143,000 shares of which were purchased by the Company during the fourth quarter
of 2001). As of February 28, 2001, we had $114.4 million of debt outstanding
under the MARAD facility and $25.2 million of debt outstanding under our $60
million revolving credit facility. In addition, as of February 28, 2001, we
(through a special purpose entity) had drawn $11.3 million on a project
financing facility covering CDI's share of costs for the construction of the
spar at Gunnison. The Company believes that internally-generated cash flow,
borrowings under existing credit facilities and use of project financings along
with other debt and equity alternatives will provide the necessary capital to
achieve our planned growth.

Operating Activities. Net cash provided by operating activities was $89.1
million during the year ended December 31, 2001, as compared to $53.7 million
during 2000. This increase was due mainly to increased profitability and
collection of a $10 million tax refund from the Internal Revenue Service
(reflected in Changes in Income Taxes Receivable) relating to the deduction of
Q4000 construction costs as research and development expenditures for federal
tax purposes. Timing of accounts payable payments provided $22.3 million of the
increase due mainly to expenses accrued at December 31, 2001 on the
Nansen/Boomvang project which carries a large component of pass-through costs.
This project also accounted for the significant increase in unbilled revenue at
December 31, 2001 ($10.7 million versus $1.9 million at December 31, 2000), as
the next scheduled invoicing milestone was achieved in January 2002. This was
offset by a $20.3 million decrease in funding from accounts receivable
collections during 2001 compared to 2000 as we have extended payment terms to
Horizon Offshore. In addition, depreciation and amortization increased $3.8
million to $34.5 million for 2001 due mainly to the depreciation of newly
acquired vessels in service.

Net cash provided by operating activities was $53.7 million in 2000, as
compared to $25.5 million in 1999. This increase was mainly due to increased
profitability as well as $23.6 million of funding from the collection of
accounts receivable during 2000 as we collected all amounts due on the EEX
Cooper abandonment project (the largest contract in our history) during the
first quarter. In addition, depreciation and amortization increased $10.1
million to $30.7 million for 2000 due mainly to ERT depletion associated with
increased production levels. These increases, along with the aforementioned
deferred tax increase, were partially offset by a $22.2 million reduction in the
level of funding from accounts payable and accrued liabilities in 2000 compared
to 1999. The 1999 levels increased primarily as a result of year-end accruals
with respect to the Q4000 construction project and the EEX project.

Investing Activities. Capital expenditures have consisted principally of
strategic asset acquisitions related to the assembly of a fleet of DP vessels,
construction of the Q4000, acquisition of Aquatica and PDNO, improvements to
existing vessels and the acquisition of offshore natural gas and oil properties.
We have consistently targeted the years 2002/2003 as the time when we expect to
see a significant acceleration in Deepwater demand. As a result, we incurred
$151.3 million of capital expenditures during 2001 compared to $95.1 million
during 2000 and $77.4 million during 1999, a level which was over five times the
prior year. Included in the $151.3 million of capital expenditures in 2001 was
$53 million for the construction of the Q4000, $33 million for the conversion of
the Intrepid, $40 million relating to the purchase of two DP vessels (the 240
foot by 52 foot Mystic Viking and the 370 foot by 67 foot Eclipse), and
production partnering expenditures of $20 million for initial Gunnison
development costs and the ERT 2001 Well Enhancement Program. In addition, in
March 2001, CDI acquired substantially all of the assets of PDNO in exchange for
$11.5 million. The assets purchased included the Sea Level 21 (a 165-foot
four-point moored DSV renamed the Mr. Sonny), three utility vessels and
associated diving equipment including two saturation diving systems. This
acquisition was accounted for as a purchase with the acquisition price of $11.5
million being allocated to the assets acquired and liabilities assumed based
upon their estimated fair values with the balance of the purchase price ($2.8
million) being recorded as excess of cost over net assets acquired (goodwill).
Included in the $95.1 million of capital expenditures in 2000 was $61.0 million
for the construction of the Q4000 and $8.5 million relating to the conversion of
the Intrepid.

ERT purchased working interests of 3% to 75% in four offshore blocks during
2001 in exchange for assumption of the pro-rata share of the decommissioning
obligations. In addition, during the first quarter of 2001 ERT purchased a
working interest of 55% in Vermilion 201 for $2.5 million from an investment
30

partnership composed of Company management and industry sources which had funded
the drilling of a deep exploratory well. Also, during the first half of 2000,
ERT acquired interests in six offshore blocks from EEX Corporation and agreed to
operate the remaining EEX properties on the OCS. The acquired offshore blocks
include working interests from 40% to 75% in five platforms, one caisson and 13
wells. ERT agreed to a purchase price of $4.9 million, assumed EEX Corporation's
pro rata share of the abandonment obligation for the acquired interests and
entered into a two-year contract to manage the remaining EEX operated
properties. During the first four months of 1999, in four separate transactions,
ERT acquired interests in 20 blocks in exchange for cash consideration, as well
as assumption of the pro rata share of the related decommissioning liabilities.
In connection with 2001, 2000 and 1999 offshore property acquisitions, ERT
assumed net abandonment liabilities of approximately $3,100,000, $4,200,000 and
$19,500,000, respectively.

ERT production activities are regulated by the Federal government and
require significant third-party involvement, such as refinery processing and
pipeline transportation. We record revenue from our offshore properties net of
royalties paid to the Minerals Management Service (MMS). Royalty fees paid
totaled approximately $15.2 million, $11.7 million and $4 million for the years
ended 2001, 2000 and 1999, 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.

In April 2000, ERT acquired a 20% working interest in Gunnison, a Deepwater
Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corporation. Consistent with
CDI's philosophy of avoiding exploratory risk, financing for the exploratory
costs (initially estimated at $15 million) was provided by an investment
partnership (OKCD Investments, Ltd.), the investors of which are CDI senior
management, in exchange for a 25% revenue override of CDI's 20% working
interest. CDI provided no guarantees to the investment partnership. At that
time, the Board of Directors established three criteria to determine a
commercial discovery and the commitment of Cal Dive funds: 75 million barrels
(gross) of reserves, total development costs of $500 million consistent with 75
MBOE, and a CDI estimated shareholder return of no less than 12%. Kerr-McGee,
the operator, drilled several exploration wells and sidetracks in 3,200 feet of
water at Garden Banks 667, 668 and 669 (the Gunnison prospect) and encountered
significant potential reserves resulting in the three criteria being achieved
during 2001. The exploratory phase was expanded to ensure field delineation
resulting in the investment partnership which assumed the exploratory risk
funding $20 million of exploratory drilling costs, considerably above the
initial $15 million estimate. With the sanctioning of a commercial discovery,
the Company will fund its share of ongoing development and production costs
estimated in a range of $100 million to $110 million ($15.8 million of which had
been incurred by December 31, 2001) with over half of that for construction of
the spar. CDI has received a commitment from a financial institution to provide
construction funding for the spar, including an option for CDI to convert this
loan facility into a long-term (20 year) leveraged lease after the spar is
placed in service. See further discussion below.

As part of the process of obtaining funding for the exploratory costs of
the Gunnison prospect and Vermilion 201, several outside third parties were
solicited. Management believes that the fund structure of these transactions was
both consistent with the guidelines and at least as favorable to the Company and
ERT as could have been obtained from the third parties.

During each of the past three years ERT has sold its interests in certain
fields as well as the platforms and a pipeline. An ERT operating policy provides
for the sale of assets when the expected future revenue stream can be
accelerated in a single transaction. The net result of these sales was to add
two cents, four cents and seven cents to diluted earnings per share in the years
2001, 2000 and 1999, respectively. These sales were structured as Section 1031
"Like Kind" exchanges for tax purposes. Accordingly, the cash received was
restricted to use for subsequent acquisitions of additional natural gas and oil
properties.

In June 2000, the DP DSV Balmoral Sea caught fire while dockside in New
Orleans, LA as the vessel was being prepared to enter drydock for an extended
period. The vessel was deemed a total loss by insurance underwriters. Her book
value (approximately $7 million) was fully insured as were all salvage and
removal costs. Payments from the insurance companies were received during the
fourth quarter of 2000.

31

In December 1999, a Cal Dive-affiliated company (CAHT I) entered into a
sale-leaseback of the Cal Dive Aker Dove. Our portion of the proceeds received
totaled $20.0 million. The lease was accounted for as an operating lease.
Effective April 1, 2001, Coflexip's acquisition of Aker enabled CDI to "put" its
interest in CAHT I back to Aker in return for Aker assuming all of CDI's
obligations and guarantees under the sale-leaseback.

Financing Activities. We have financed seasonal operating requirements and
capital expenditures with internally generated funds, borrowings under credit
facilities, the sale of common stock and project financings. In August 2000, the
Company closed a $138.5 million 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). In January 2002, the Maritime Administration agreed to expand the
facility to $160 million to include the modifications to the vessel which had
been approved during 2001. At the time the financing closed in 2000, the Company
made an initial draw of $40.1 million toward construction costs. During 2001,
the Company borrowed $59.5 million on this facility and expects to draw the
remaining commitment during 2002. The MARAD Debt will be payable in equal semi-
annual installments beginning six months after delivery of the newbuild Q4000
and maturing 25 years from such date. It is collateralized by the Q4000, with
CDI guaranteeing 50% of the debt, and bears an interest rate which currently
floats at a rate approximating AAA Commercial Paper yields plus 20 basis points
(2.25% as of December 31, 2001). For a period up to two years from delivery of
the vessel CDI has options 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 and debt-to-equity
requirements. As of December 31, 2001, the Company was in compliance with these
covenants.

Since April 1997, the Company has had a revolving credit facility of $40
million available. The Company drew upon this facility only 134 days during the
four years ended December 31, 2001 with maximum borrowing of $11.9 million. The
Company had no outstanding balance under this facility as of December 31, 2001.
In February 2002, the Company amended this facility, expanding the amount
available to $60 million and extending the term three years. This facility is
collateralized by accounts receivable and most of the remaining vessel fleet,
bears interest at LIBOR plus 125-250 basis points depending on CDI leverage
ratios and, among other restrictions, includes three financial covenants (cash
flow leverage, minimum interest coverage and fixed charge coverage).

In November 2001, ERT (with a corporate guarantee by CDI) entered into a
five-year lease transaction with a special purpose entity owned by a third party
to fund CDI's portion of the construction costs ($67 million) of the spar for
the Gunnison field. This lease is expected to be accounted for as an operating
lease upon completion of the construction, and includes an option for the
Company to convert the lease into a long-term (20 year) leveraged lease after
construction is completed. As of December 31, 2001, the special purpose entity
had drawn down $5.6 million on this facility. Accrued interest cost on the
outstanding balance is capitalized to the cost of the facility during
construction and is payable monthly thereafter. The principal balance of $67
million is due at the end of five years if the long-term leverage lease option
is not taken. The facility bears interest at LIBOR plus 225-300 basis points
depending on CDI leverage ratios and includes, among other restrictions, three
financial covenants (cash flow leverage, minimum interest coverage and debt to
total book capitalization). The Company was in compliance with these covenants
as of December 31, 2001.

32

The following table summarizes the Company's contractual cash obligations
as of December 31, 2001 and the scheduled years in which the obligations are
contractually due (in thousands):

In January 2002, CDI acquired approximately 85% of Canyon Offshore, Inc.
(Canyon), a supplier of remotely operated vehicles (ROVs) and robotics to the
offshore construction and telecommunications industries, in exchange for cash of
$51 million, the assumption of $5 million of Canyon net debt and 181,000 shares
of CDI common stock (143,000 shares of which were purchased by the Company
during the fourth quarter of 2001 for $2.6 million). Cal Dive will purchase the
remaining 15% at a price to be determined by Canyon's performance during the
years 2002 through 2004, a portion of which could be compensation expense. The
total purchase price is estimated to range from $66 million to $74 million. The
acquisition will be accounted for as a purchase with the acquisition price being
allocated to the assets acquired and liabilities assumed based upon their
estimated fair values, with the excess being recorded as goodwill, which is
initially estimated at approximately $40 million.

In September 2000, CDI completed a Secondary stock offering with Coflexip
selling its 7.4 million shares of common stock at $26.31 per share. The
over-allotment option was exercised resulting in the Company issuing 609,936
shares of common stock and receiving net proceeds of $14.8 million.

In October 2000, our Board of Directors declared a two-for-one split of
CDI's common stock in the form of a 100% stock distribution on November 13, 2000
to all holders of record at the close of business on October 30, 2000. All share
and per share data in these financial statements have been restated to reflect
the stock split.

The only other financing activity during 2001, 2000 and 1999 represents the
exercise of employee stock options.

Capital Commitments. Our Board of Directors has approved a capital budget
for 2002 which includes $50 million for the completion of the Q4000 and
Intrepid, $65 million for the purchase of Canyon Offshore and the addition of
three new Quest ROV units, and approximately $30 million as the equity portion
of the construction of the Marco Polo production facility. In addition, it is
estimated that CDI will be required to fund $19 million for Gunnison development
expenditures in addition to an estimated $34 million which will be funded by the
project financing established for the construction of the spar. In December
2001, CDI signed a letter of intent to form a 50-50 venture with El Paso Energy
Partners to construct, install and own a Deepwater production hub platform and
associated facilities primarily for Anadarko Petroleum Corporation's Marco Polo
field discovery at Green Canyon 608 in the Gulf of Mexico. CDI's share of the
construction costs is estimated to be $100 million. CDI, along with El Paso, is
currently negotiating project financing for this venture, terms of which would
include a 30% equity component for CDI.

In connection with our business strategy, we evaluate acquisition
opportunities (including additional vessels as well as interests in offshore
natural gas and oil properties). No such acquisitions are currently pending.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

A variety of quantitative and qualitative factors affect the operations of
the Company. For more information see "Factors Influencing Future Results and
Accuracy of Forward-Looking Statements".

33

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

34

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have audited the accompanying consolidated balance sheets of Cal Dive
International, Inc. (a Minnesota corporation) and subsidiaries as of December
31, 2001 and 2000, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles 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 financial position of Cal Dive International,
Inc., and subsidiaries as of December 31, 2001 and 2000, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States.

ARTHUR ANDERSEN LLP

Houston, Texas
February 18, 2002

35

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
(IN THOUSANDS)

The accompanying notes are an integral part of these consolidated financial
statements.
36

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

The accompanying notes are an integral part of these consolidated financial
statements.
37

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(IN THOUSANDS)

The accompanying notes are an integral part of these consolidated financial
statements.
38

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(IN THOUSANDS)

The accompanying notes are an integral part of these consolidated financial
statements.
39

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, owns, staffs and operates twenty-two marine construction
vessels and a derrick barge in the Gulf of Mexico. The Company provides a full
range of services to offshore oil and gas exploration and production and
pipeline companies, including underwater construction, well operations,
maintenance and repair of pipelines and platforms, and salvage operations.
Diving and vessel support services in the shallow water market are provided by
Aquatica, Inc., a wholly-owned subsidiary based in Lafayette, Louisiana. In
January 2002, the Company expanded its Deepwater services through acquisition of
Canyon Offshore, Inc. See footnote 17.

In September 1992, Cal Dive formed a wholly-owned subsidiary, Energy
Resource Technology, Inc. (ERT), to purchase non-core producing offshore oil and
gas properties and those which are in the later stages of their economic lives.
ERT is a fully bonded offshore operator and, in conjunction with the acquisition
of properties, assumes the responsibility to decommission the property in full
compliance with all governmental regulations. CDI has expanded the scope of its
gas and oil operations by taking a working interest in Gunnison, a Deepwater
development of Kerr-McGee Oil & Gas Corporation which has encountered
significant reserves. The company is expanding its Deepwater Hub strategy by
agreeing to participate in the ownership of the Marco Polo production facility.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

The accompanying consolidated financial statements include the accounts of
the Company and its subsidiaries. All significant intercompany accounts and
transactions have been eliminated.

GOODWILL

Through the end of 2001, goodwill was amortized on the straight-line method
over its estimated useful life. Accumulated amortization as of December 31, 2001
and 2000 was $1.9 million and $1.2 million, respectively. The Company
continually evaluated whether subsequent events or circumstances had occurred
which indicated that the remaining useful life of goodwill might warrant
revision or that the remaining balance of goodwill might not be recoverable.
Management believes that there have been no events or circumstances which
warrant revision to the remaining useful life or which affect recoverability of
goodwill.

In July 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 141, Business
Combinations, which supersedes Accounting Principles Board (APB) Opinion No. 16,
Business Combinations. SFAS 141 eliminates the pooling-of-interests method of
accounting for business combinations and modifies the application of the
purchase accounting method. The provisions of SFAS 141 were effective for
transactions accounted for using the purchase method completed after June 30,
2001. The Company had no business combination completed between June 30, 2001
and December 31, 2001.

In July 2001, the FASB also issued SFAS No. 142, Goodwill and Intangible
Assets, which supersedes APB Opinion No. 17, Intangible Assets. SFAS 142
eliminates the current requirement to amortize goodwill and indefinite-lived
intangible assets, addresses the amortization of intangible assets with a
defined life and addresses the impairment testing and recognition for goodwill
and intangible assets. SFAS 142, which is effective for 2002, will apply to
goodwill and intangible assets arising from transactions completed before and
after the statement's effective date. The Company believes adoption of this
standard will have an immaterial effect on CDI's financial position and results
of operations.

40

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

PROPERTY AND EQUIPMENT

Property and equipment 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 natural gas and oil properties are
located offshore in United States waters. The Company follows the successful
efforts method of accounting for its interests in natural gas and oil
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.

ERT acquisitions of producing offshore properties are recorded at the value
exchanged at closing together with an estimate of its proportionate share of the
undiscounted 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. 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.

In July 2001, the FASB released SFAS No. 143, Accounting for Asset
Retirement Obligations, which is required to be adopted by the Company no later
than January 1, 2003. SFAS No. 143 addresses the financial accounting and
reporting obligations and retirement costs related to the retirement of tangible
long-lived assets. The Company is currently reviewing the provisions of SFAS No.
143 to determine the standard's impact, if any, on its financial statements upon
adoption. Among other things SFAS No. 143 will require oil and gas companies to
reflect decommissioning liabilities on the face of the balance sheet, something
ERT has done since inception on an undiscounted basis.

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

In July 1999, the CDI Board of Directors approved the construction of the
Q4000, a newbuild, ultra-deepwater multi-purpose vessel, for a total estimated
cost of $150 million and, in June 2001, approved modification to the original
construction contract increasing the total estimated costs to $182 million.
Amounts incurred on this project and the conversion of the Intrepid pipelay
vessel are included in Construction in Progress ($1.9 million of which is
capitalized interest).

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 $8,501,000, $4,343,000 and $6,031,000 for
the years ended December 31, 2001, 2000 and 1999, respectively.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets, which is effective for the Company beginning
January 1, 2002. SFAS No. 144 supersedes SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and
the accounting and reporting provisions relating to the disposal of a segment of
a business of APB Opinion

41

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

No. 30. The Company believes that the adoption of SFAS No. 144 will not have a
material impact on its financial position or results of operations.

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. Actual results could differ from those estimates.

EARNINGS PER SHARE

The Company computes and presents earnings per share in accordance with
SFAS No. 128, Earnings Per Share. SFAS 128 requires the presentation of "basic"
EPS and "diluted" EPS on the face of the statement of operations. Basic EPS is
computed by dividing the net income available to common shareholders by the
weighted-average shares of outstanding common stock. The calculation of diluted
EPS is similar to basic EPS except that the denominator includes dilutive common
stock equivalents, which were stock options, less the number of treasury shares
assumed to be purchased from the proceeds with the exercise of stock options.

REVENUE RECOGNITION

The Company earns the majority of its subsea service and salvage
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. 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. Contract price and cost estimates are
reviewed periodically as work progresses and adjustments are reflected in the
period in which such estimates are revised. Provisions for estimated losses on
such contracts are made in the period such losses are determined. Unbilled
revenue represents revenue attributable to work completed prior to year-end
which has not yet been invoiced. All amounts included in unbilled revenue at
December 31, 2001 are expected to be billed and collected within one year.

REVENUE ALLOWANCE ON GROSS AMOUNTS BILLED

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

MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK

The market for the Company's products and services is the offshore oil and
gas industry. Oil and gas companies make capital expenditures on exploration,
drilling and production operations offshore, the level of which is generally
dependent on the prevailing view of the future oil and gas prices, which have
been characterized by significant volatility in recent years. 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: 2001 -- Horizon Offshore, Inc. (18%), Enron Corporation (10%);
2000 -- Enron Corporation (13%); and 1999 -- EEX Corporation (13%).
42

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In March 2001, CDI and Horizon Offshore, Inc. announced that the Alliance
Agreement covering operation on the Outer Continental Shelf was extended for a
three-year period. Principal features of the Alliance are that CDI provides Dive
Support Vessel services behind Horizon pipelay barges while Horizon supplies
pipelay, derrick barge and heavy lift capacity to Cal Dive. The Alliance was
also expanded to include CDI providing the diving personnel working from Horizon
barges, a service Horizon handled internally in 2000. During 2001 the Company
also provided dynamically positioned vessels to support Horizon projects for
Pemex in Mexican waters of the Gulf of Mexico.

INCOME TAXES

Deferred taxes are recognized for revenues and expenses reported in
different years for financial statement purposes and income tax purposes in
accordance with SFAS No. 109, Accounting for Income Taxes. The statement
requires, among other things, the use of the liability method of computing
deferred income taxes. The liability method is based on the amount of current
and future taxes payable using tax rates and laws in effect at the balance sheet
date.

DEFERRED DRYDOCK CHARGES

The Company accounts for regulatory (U.S. Coast Guard, American Bureau of
Shipping and Det Norske Veritas) related drydock inspection and certification
expenditures by capitalizing the related costs and amortizing them over the
30-month period between regulatory mandated drydock inspections and
certification. During the years ended December 31, 2001, 2000 and 1999, drydock
amortization expense was $3.1 million, $2.2 million and $1.7 million,
respectively. This predominant industry practice provides appropriate matching
of expenses with the period benefitted (i.e., certification to operate the
vessel for a 30-month period between required drydock inspections).

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. During
the years ended December 31, 2001, 2000 and 1999, the Company made cash payments
for interest charges, net of interest capitalized, of $662,000, $-0- and $-0-,
respectively, and made cash payments for federal income taxes of approximately
$-0-, $1,800,000 and $4,075,000, respectively.

RECLASSIFICATIONS

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

3. ACQUISITION OF DEEPWATER VESSELS

In May 2001, Cal Dive acquired a dynamically positioned (DP) marine
construction vessel, the Mystic Viking (formerly the Bergen Viking). The 240
foot by 52 foot vessel is DP-2 class, similar to the Witch Queen. The Mystic
Viking replaces the Balmoral Sea (lost during 2000) and the Cal Dive Aker Dove
(Cal Dive's ownership was transferred to Aker effective April 1, 2001).

In October 2001, Cal Dive announced the acquisition of another DP marine
construction vessel, the Eclipse (formerly the C.S. Seaspread). The 370 foot by
67 foot vessel is a sister ship to Coflexip Stena Offshore's Constructor and
EMC's Bar Protector. She was sold out of the energy services industry into the
telecom cable sector in the early 1990s. Following delivery in the first quarter
of 2002, her original marine construction features will be restored by
installing a saturation diving system (salvaged from the Balmoral Sea),
restoring the ballast system, and upgrading the DP system to DP-2 standards. The
total cost of the two

43

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

vessels acquired and related upgrades will approximate $40 million, the majority
of which has been expended as of December 31, 2001.

4. OFFSHORE PROPERTY TRANSACTIONS

ERT purchased working interests of 3% to 75% in four offshore blocks during
2001 in exchange for assumption of the pro-rata share of the decommissioning
obligations. In addition, during 2001 ERT purchased a working interest of 55% in
Vermilion 201 for $2.5 million (see footnote 5). In the first quarter of 2000,
ERT acquired interests in six offshore blocks from EEX Corporation and agreed to
operate the remaining EEX properties on the Outer Continental Shelf (OCS). The
acquired offshore blocks include working interests from 40% to 75% in five
platforms, one caisson and 13 wells. ERT agreed to a purchase price of $4.9
million and assumed EEX's prorated share of the abandonment obligation for the
acquired interests, and entered into a two-year contract to manage the remaining
EEX operated properties. Additionally, in April 2000, ERT acquired a 20%
interest in Gunnison. See further discussion in footnote 5. During the first
four months of 1999, in four separate transactions, ERT acquired interests in 20
blocks and interests in six blocks involving two separate fields in exchange for
cash as well as assumption of the pro-rata share of the related decommissioning
liabilities. In connection with 2001, 2000 and 1999 offshore property
acquisitions, ERT assumed net abandonment liabilities estimated at approximately
$3,100,000, $4,200,000, and $19,500,000 respectively.

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 $15.2 million, $11.7 million and $4
million for the years ended 2001, 2000 and 1999, respectively. In accordance
with federal regulations that require operators in the Gulf of Mexico to post an
area wide bond of $3 million, the MMS has allowed the Company to fulfill such
bonding requirements through an insurance policy.

During each of the past three years ERT has sold its interests in certain
fields as well as the platforms and a pipeline. An ERT operating policy provides
for the sale of assets when the expected future revenue stream can be
accelerated in a single transaction. The net result of these sales was to add
two cents, four cents and seven cents to diluted earnings per share for the
years ending December 31, 2001, 2000 and 1999, respectively. These sales were
structured as Section 1031 "Like Kind" exchanges for tax purposes. Accordingly,
the cash received was restricted to use for subsequent acquisitions of
additional natural gas and oil properties.

5. 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 Corporation. Consistent with
CDI's philosophy of avoiding exploratory risk, financing for the exploratory
costs (initially estimated at $15 million) was provided by an investment
partnership (OKCD Investments, Ltd.), the investors of which are CDI senior
management, in exchange for a 25% revenue override of CDI's 20% working
interest. CDI provided no guarantees to the investment partnership. At this
time, the Board of Directors established three criteria to determine a
commercial discovery and the commitment of Cal Dive funds: 75 million barrels
(gross) of reserves, total development costs of $500 million consistent with 75
MBOE, and a CDI estimated shareholder return of no less than 12%. Kerr-McGee,
the operator, drilled several exploration wells and sidetracks in 3,200 feet of
water at Garden Banks 667, 668 and 669 (the Gunnison prospect) and encountered
significant potential reserves resulting in the three criteria being achieved
during 2001. The exploratory phase was expanded to ensure field delineation
resulting in the investment partnership which assumed the exploratory risk
funding over $20 million of exploratory drilling costs, considerably above the
initial $15 million estimate. With the sanctioning of a commercial discovery,
the Company will fund ongoing development and production costs. Cal Dive's share
of

44

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

such project development costs is estimated in a range of $100 million to $110
million ($15.8 million of which had been incurred by December 31, 2001) with
over half of that for construction of the spar. CDI has received a commitment
from a financial institution to provide a construction funding for the spar,
including an option for CDI to convert this loan facility into a long-term (20
year) leveraged lease after the spar is placed in service. See footnote 10.

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

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

6. ACQUISITION OF PROFESSIONAL DIVERS OF NEW ORLEANS, INC. (PDNO) AND AQUATICA,
INC.

In March 2001, CDI acquired substantially all of the assets of Professional
Divers of New Orleans, Inc. (PDNO) in exchange for $11.5 million. The assets
purchased included the Sea Level 21 (a 165-foot four-point moored DSV renamed
the Mr. Sonny), three utility vessels and associated diving equipment including
two saturation diving systems. This acquisition was accounted for as a purchase
with the acquisition price of $11.5 million being allocated to the assets
acquired and liabilities assumed based upon their estimated fair values with the
balance of the purchase price ($2.8 million) being recorded as excess of cost
over net assets acquired (goodwill).

In February 1998, CDI purchased a significant minority equity interest in
Aquatica, Inc., a shallow water diving company. CDI accounted for this
investment on the equity basis of accounting for financial reporting purposes.
The related Shareholder Agreement provided that the remaining shares of
Aquatica, Inc. could be converted into Cal Dive shares based on a formula which,
among other things, valued the shares of Aquatica, Inc. Effective August 1,
1999, 1.4 million shares of common stock of Cal Dive were issued for all of the
remaining common stock of Aquatica, Inc. pursuant to these terms. This
acquisition was accounted for as a purchase with the acquisition price of $16.2
million being allocated to the assets acquired and liabilities assumed based
upon their estimated fair values. The fair value of tangible assets acquired and
liabilities assumed was $6.4 million and $2.2 million, respectively. The balance
of the purchase price ($12 million) was recorded as excess of cost over net
assets acquired (goodwill). Results of operations for Aquatica, Inc. are
consolidated with those of Cal Dive for periods subsequent to August 1, 1999.

7. ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in thousands):

45

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8. LONG-TERM DEBT

In August 2000, the Company closed a $138.5 million 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"). In January 2002, the Maritime
Administration agreed to expand the facility to $160 million to include the
modifications to the vessel which had been approved during 2001. At the time the
financing closed in 2000, the Company made an initial draw of $40.1 million
toward construction costs. During 2001, the Company borrowed $59.5 million on
this facility and expects to draw the remaining commitment during 2002.

The MARAD Debt will be payable in equal semi-annual installments beginning
six months after delivery of the newbuild Q4000 and maturing 25 years from such
date. It is collateralized by the Q4000, with CDI guaranteeing 50% of the debt,
and bears an interest rate which currently floats at a rate approximating AAA
Commercial Paper yields plus 20 basis points (2.25% as of December 31, 2001).
For a period up to two years from delivery of the vessel CDI has options 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 and debt-to-equity requirements. As of December 31, 2001, the
Company was in compliance with these covenants.

Since April 1997, the Company has had a revolving credit facility of $40
million available. The Company drew upon this facility only 134 days during the
past four years with maximum borrowing of $11.9 million. The Company had no
outstanding balance under this facility as of December 31, 2001. In February
2002, the Company amended this facility, expanding the amount available to $60
million and extending the term three years. This facility is collateralized by
accounts receivable and most of the remaining vessel fleet, bears interest at
LIBOR plus 125-250 basis points depending on CDI leverage ratios and, among
other restrictions, includes three financial covenants (cash flow leverage,
minimum interest coverage and fixed charge coverage). As of February 18, 2002,
the Company had drawn $22 million under this revolving credit facility. See
project financing of Gunnison spar at footnote 10.

9. FEDERAL INCOME TAXES

Federal income taxes have been provided based on the 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):

46

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Deferred income taxes result from those transactions which affect financial
and taxable income in different years. The nature of these transactions and the
income tax effect of each as of December 31, 2001 and 2000, is as follows (in
thousands):

CDI effectively paid no federal income taxes in 2001 and 2000 due to the
deduction of Q4000 construction costs as research and development for federal
tax purposes. The Company paid $1.8 million of federal income taxes during 2000,
but the amount was refunded in January 2001 upon completing our research and
development analysis and filing for the refund. In addition, we filed amended
tax returns for 1998 and 1999, deducting such costs, resulting in refunds of
$8.2 million which were collected in January 2001. These amounts were reflected
as Income Tax Receivable in the accompanying consolidated balance sheets as of
December 31, 2000.

10. COMMITMENTS AND CONTINGENCIES:

LEASE COMMITMENTS

During 1999, CDI acquired an interest in Cal Dive Aker CAHT I, LLC (CAHT
I), the company which owned the Cal Dive Aker Dove (a newbuild DP anchor
handling and subsea construction vessel which commenced operations in September
1999) for a total of $18.9 million. CDI effectively owned 56% of CAHT I and,
accordingly, results of operations of this company were consolidated in the
accompanying financial statements with Aker's share being reflected as minority
interest. In December, 1999 CAHT I entered into a sale-leaseback of the Cal Dive
Aker Dove. Cal Dive's portion of the sale proceeds received totaled $20 million.
The lease was accounted for as an operating lease. Effective April 1, 2001,
Coflexip's acquisition of Aker enabled CDI to "put" its interest in CAHT I back
to Aker in return for Aker assuming all of CDI's obligations and guarantees
under the sale-leaseback.

In November 2001, ERT (with a corporate guarantee by CDI) entered into a
five-year lease transaction with a special purpose entity owned by a third party
to fund CDI's portion of the construction costs ($67 million) of the spar for
the Gunnison field. This lease is expected to be accounted for as an operating
lease upon completion of the construction and includes an option for the Company
to convert the lease into a long-term (20 year) leveraged lease after
construction is completed. As of December 31, 2001, the special purpose entity
had drawn down $5.6 million on this facility. Accrued interest cost on the
outstanding balance is capitalized to the cost of the facility during
construction and are payable monthly thereafter. The principal balance of $67
million is due at the end of five years if the long-term leverage lease option
is not taken. The facility bears interest at LIBOR plus 225-300 basis points
depending on CDI leverage ratios and includes, among other restrictions, three
financial covenants (cash flow leverage, minimum interest coverage and debt to
total book capitalization). The Company was in compliance with these covenants
as of December 31, 2001.

The Company occupies several facilities under noncancelable operating
leases, with the more significant leases expiring in the years 2004 and 2007.
Future minimum rentals under these leases are $2,380,000 at December 31, 2001
with $701,000 due in 2002, $669,000 in 2003, $605,000 in 2004, $135,000 in 2005,

47

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$135,000 in 2006 and $135,000 thereafter. Total rental expense under these
operating leases was $779,000, $721,000 and $673,000 for the years ended
December 31, 2001, 2000 and 1999, respectively.

In December 2001, CDI signed a letter of intent to form a 50-50 venture
with El Paso Energy Partners to construct, install and own a Deepwater
production hub platform and associated facilities primarily for Anadarko
Petroleum Corporation's Marco Polo field discovery at Green Canyon 608 in the
Gulf of Mexico. CDI's share of the construction costs is estimated to be $100
million. CDI, along with El Paso, is currently negotiating project financing for
this venture, terms of which would include a 30% equity component for CDI.

INSURANCE

The Company carries Hull and Increased Value insurance which provides
coverage for physical damage to an agreed amount for each vessel. The
deductibles are based on the value of the vessel with a maximum deductible of
$500,000 on the Q4000. Other vessels carry deductibles between $100,000 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 an
Excess Maritime Employers Liability insurance policy which covers Jones Act
exposures and includes a deductible of $50,000 per occurrence. In excess of the
liability policies named above, the Company carries various layers of Umbrella
Liability for total limits of $135,000,000 excess of primary for all vessels
except the Q4000. Total limits on the Q4000 are $160,000,000 excess of primary.
The Company's self insured retention on its medical and health benefits program
for employees is $50,000 per claim.

In June 2000, the DP DSV Balmoral Sea caught fire while dockside in New
Orleans, LA as the vessel was being prepared to enter drydock for an extended
period. The vessel was deemed a total loss by insurance underwriters. Her book
value (approximately $7 million) was fully insured as were all salvage and
removal costs. Payments from the insurance companies were received during the
fourth quarter of 2000.

The Company incurs workers' compensation claims in the normal course of
business, which management believes are covered by insurance. The Company, its
insurers and legal counsel analyze each claim for potential exposure and
estimate the ultimate liability of each claim. Amounts accrued and receivable
from insurance companies, above the applicable deductible limits, are reflected
in other current assets in the consolidated balance sheet. Such amounts were
$6,276,000 and $6,133,000 as of December 31, 2001 and 2000, 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

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 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. The Company believes that the outcome of all such
proceedings would not have a material adverse effect on its consolidated
financial position, results of operations or net cash flows.

In 1998, the Company entered into a subcontract with Seacore Marine
Contractors Limited to provide the Sea Sorceress for subsea excavation in
Canada. Seacore was in turn contracted by Coflexip Stena Offshore Newfoundland
Limited, a subsidiary of Coflexip ("CSO Nfl"), as representative of the
consortium of companies contracted to perform services on the project. Due to
difficulties with respect to the sea states and soil conditions the contract was
terminated. Cal Dive provided Seacore a performance bond of $5 million with
respect to the subcontract. No call has been made on this bond. Although CSO Nfl
has alleged that the Sea Sorceress was unable to adequately perform the
excavation work required under the subcontract, Seacore and

48

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the Company believe the contract was wrongfully terminated and are vigorously
defending this claim and seeking damages in arbitration. In another commercial
dispute, EEX Corporation sued Cal Dive and others alleging breach of fiduciary
duty by a former EEX employee and damages resulting from certain construction
and property acquisition agreements. Cal Dive has responded alleging EEX
Corporation breached various provisions of the same contracts and is seeking a
declaratory judgment that the defendants are not liable. Although such
litigation has the potential of significant liability, the Company believes that
the outcome of all such proceedings is not likely to have a material adverse
effect on its consolidated financial position, results of operations or net cash
flows.

11. 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 $595,000, $423,000 and $375,000 for the years ended
December 31, 2001, 2000 and 1999, 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 2001 and 2000 resulting in a total of 180,000 and 115,000 options
being granted during 2001 and 2000, respectively (which includes bonuses earned
under the annual incentive compensation program in both years).

During 1995, the Board of Directors and shareholders approved the 1995
Long-Term Incentive Plan (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. The
Incentive Plan is administered by a committee which determines, subject to
approval of the Compensation Committee of the Board of Directors, the type of
award to be made to each participant and sets forth in the related award
agreement the terms, conditions and limitations applicable to each award. The
committee may grant stock options, stock appreciation rights, or stock and cash
awards. Options granted to employees under the Incentive Plan vest 20% per year
for a five year period or 33% per year for a three year period, have a maximum
exercise life of three, five or ten years and, subject to certain exceptions,
are not transferable.

Effective May 12, 1998, the Company adopted a qualified, non-compensatory
Employee Stock Purchase Plan ("ESPP"), which allows employees to acquire shares
of common stock through payroll deductions over a six month period. The purchase
price is equal to 85 percent of the fair market value of the common stock on
either the first or last day of the subscription period, whichever is lower.
Purchases under the plan are limited to 10 percent of an employee's base salary.
Under this plan 38,849, 25,391 and 22,476 shares of common stock were purchased
in the open market at a weighted average share price of $22.22, $21.55 and
$12.19 during 2001, 2000 and 1999, respectively.

The above plans are accounted for using APB Opinion No. 25, and therefore
no compensation expense is recorded. If SFAS Statement No. 123 had been used for
the accounting of these plans, the Company's pro forma net income for 2001, 2000
and 1999 would have been $25,879,000, $21,665,000 and $16,218,000,

49

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

respectively, and the Company's pro forma diluted earnings per share would have
been $0.79, $0.67 and $0.53, respectively. These pro forma results exclude
consideration of options granted prior to January 1, 1995, and therefore may not
be representative of that to be expected in future years.

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 5.5 percent in
1999, 5.0 percent in 2000 and 4.5 percent in 2001, and expected volatility to be
59 percent in 1999, 62 percent in 2000 and 61 percent in 2001. The fair value of
shares issued under the ESPP was based on the 15% discount received by the
employees.

All of the options outstanding at December 31, 2001, have exercise prices
as follows: 97,554 shares at $3.95, 579,000 at $4.75, 108,520 shares at $10.28,
211,668 shares at $18.00, 119,508 shares at $18.06, 129,000 shares at $19.63,
297,000 shares at $21.88 and 636,996 shares ranging from $6.50 to $26.75 and a
weighted average remaining contractual life of 3.98 years.

Options granted in 1999 include 287,278 shares issued in connection with
the August 1, 1999 acquisition of Aquatica, Inc., which provided for conversion
of Aquatica employee stock options into Cal Dive stock options at the same ratio
which Aquatica common shares were converted into Cal Dive common shares.

Options outstanding are as follows:

12. COMMON STOCK

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.

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

In October 2000, the Board of Directors declared a two-for-one split of
CDI's common stock in the form of a 100% stock distribution on November 13, 2000
to all holders of record at the close of business on October 30, 2000. All share
and per share data in these financial statements have been restated to reflect
the stock split.

In September 2000, CDI completed a Secondary Stock Offering with Coflexip
selling its 7.4 million shares of common stock at $26.31 per share. The
over-allotment option was exercised resulting in the Company issuing 609,936
shares of common stock and receiving net proceeds of $14.8 million, and the
Chief Executive Officer, selling 500,000 shares.

50

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. BUSINESS SEGMENT INFORMATION (IN THOUSANDS)

The following summarizes certain financial data by business segment:

14. 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).

51

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

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. As of December 31, 2001 and
2000, such liabilities totaled $29.3 million and $27.5 million, respectively,
and are also reflected as decommissioning liabilities in the accompanying
consolidated balance sheets.

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

The following table reflects the costs incurred in oil and gas property
acquisition and development activities during the years indicated:

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES

Proved developed oil and gas reserve quantities are based on estimates
prepared by Company engineers in accordance with guidelines established by the
Securities and Exchange Commission. The Company's estimates of reserves at
December 31, 2001, excluding Gunnison, have been reviewed by Miller and Lents,
Ltd., independent petroleum engineers. Reserves attributable to Gunnison rely on
the operator's estimate of proved reserves. The Company does not own a license
to the geophysical data necessary for assessment of reserves and therefore, must
rely on the operator's estimate of proved reserves. All of the Company's
reserves are located in the United States. Proved reserves cannot be measured
exactly because the estimation of

52

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 1999, 337,500 Bbls. of oil and 284,800 Mcf. of gas were
undeveloped. As of December 31, 2000, -0- Bbls. of oil and -0- Mcf. of gas of
the Company's proven reserves were undeveloped. As of December 31, 2001,
6,829,000 Bbls. of oil and 35,525,000 Mcf. of gas were undeveloped, all of which
is attributable to Gunnison.

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:

53

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:

15. REVENUE ALLOWANCE ON GROSS AMOUNTS BILLED

The following table sets forth the activity in the Company's Revenue
Allowance on Gross Amounts Billed for each of the three years in the period
ended December 31, 2001 (in thousands):

See Note 2 for a detailed discussion regarding the Company's accounting
policy on the Revenue Allowance on Gross Amounts Billed. Approximately $1.8
million of such reserves at December 31, 2001 are related to the Enron
Corporation bankruptcy.

16. 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,

54

CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 2001 and 2000.

17. SUBSEQUENT EVENTS

CANYON OFFSHORE, INC. ACQUISITION

In January 2002, CDI acquired approximately 85% of Canyon Offshore, Inc.
(Canyon), a supplier of remotely operated vehicles (ROVs) and robotics to the
offshore construction and telecommunications industries, in exchange for cash of
$51 million, the assumption of $5 million of Canyon net debt and 181,000 shares
of CDI common stock (143,000 shares of which were purchased by the Company
during the fourth quarter of 2001). Cal Dive will purchase the remaining 15% at
a price to be determined by Canyon's performance during the years 2002 through
2004, a portion of which could be compensation expense. The total purchase price
is estimated to range from $66 million to $74 million. The acquisition will be
accounted for as a purchase with the acquisition price being allocated to the
assets acquired and liabilities assumed based upon their estimated fair values,
with the excess being recorded as goodwill, which is initially estimated at
approximately $40 million.

55

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

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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 2001 Annual
Meeting of Shareholders. See also "Executive Officers of the Registrant"
appearing in Part I of this Report.

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 2001 Annual
Meeting of Shareholders.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 2001 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 2001 Annual
Meeting of Shareholders.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(1) Financial Statements

The following financial statements included on pages 28 through 45 in this
Annual Report are for the fiscal year ended December 31, 2001.

Independent Auditors' Report.
Consolidated Balance Sheets as of December 31, 2001 and 2000.
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2000 and 1999.
Consolidated Statements of Shareholders' Equity for the
Years Ended December 31, 2001, 2000 and 1999.
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999.
Notes to Consolidated Financial Statements.
Financial Statement Schedules

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

(2) Report on Form 8-K.

November 1, 2000.

56

(3) Exhibits.

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

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

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

* Filed herewith.

57

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 27, 2002

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.

58

INDEX TO EXHIBITS

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

* Filed herewith.