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Helix Energy Solutions Group Inc – ‘424B4’ on 5/22/02

On: Wednesday, 5/22/02, at 12:37pm ET · Accession #: 950129-2-2696 · File #: 333-87620

  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 5/22/02  Helix Energy Solutions Group Inc  424B4                  1:261K                                   Bowne - Houston/FA

Prospectus — Rule 424(b)(4)
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 424B4       Cal Dive International Inc - Reg.No. 333-87620        76    393K

Document Table of Contents

Page	(sequential)	\|	(alphabetic)	Top
			Alternative Formats (Word, et al.) Business Capitalization Certain Anti-takeover Provisions Common Stock Price Range Consolidated Balance Sheets Description of Capital Stock Dividend Policy Experts Financing activities Gross profit Houston, Texas Index to Consolidated Financial Statements Industry, The Information Incorporated by Reference Investing activities Legal Matters Liquidity and Capital Resources Management Management's Discussion and Analysis of Financial Condition and Results of Operations Net income Net interest (income) expense and other Notes to Consolidated Financial Statements Offering, The Operating activities Other Matters Prospectus Summary Report of Independent Public Accountants Revenues Risk Factors Selected Historical Financial and Operating Data Special Note Regarding Forward-Looking Statements Spot Market The Industry The Offering Underwriters Use of Proceeds Where You Can Find More Information
1	1st Page - Filing Submission
4	Prospectus Summary
7	The Offering
9	Risk Factors
12	Special Note Regarding Forward-Looking Statements
13	Use of Proceeds
"	Common Stock Price Range
"	Dividend Policy
14	Capitalization
15	Selected Historical Financial and Operating Data
17	Management's Discussion and Analysis of Financial Condition and Results of Operations
19	Revenues
20	Gross profit
"	Net interest (income) expense and other
"	Net income
22	Liquidity and Capital Resources
23	Operating activities
"	Investing activities
25	Financing activities
28	The Industry
29	Spot Market
30	Business
41	Management
43	Description of Capital Stock
"	Certain Anti-takeover Provisions
47	Underwriters
49	Legal Matters
"	Experts
"	Other Matters
50	Where You Can Find More Information
"	Information Incorporated by Reference
51	Index to Consolidated Financial Statements
52	Report of Independent Public Accountants
"	Houston, Texas
53	Consolidated Balance Sheets
57	Notes to Consolidated Financial Statements

424B4 1st Page of 76 TOC ↑Top Previous Next ↓Bottom Just 1st
Filed Pursuant to Rule 424B4
Registration No. 333-87620

PROSPECTUS

3,444,560 Shares

[CAL DIVE INTERNATIONAL LOGO]

Cal Dive International, Inc.

COMMON STOCK
------------------------

CAL DIVE INTERNATIONAL, INC. IS OFFERING 3,444,560 SHARES OF ITS COMMON STOCK.

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

OUR COMMON STOCK IS QUOTED ON THE NASDAQ NATIONAL MARKET UNDER THE SYMBOL
"CDIS". ON MAY 21, 2002, THE REPORTED LAST SALE PRICE OF OUR COMMON STOCK ON THE
NASDAQ NATIONAL MARKET WAS $23.16 PER SHARE.

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

INVESTING IN OUR COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING ON
PAGE 9.
------------------------
PRICE $23.16 A SHARE

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

[Download Table]

UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS CAL DIVE
-------- ------------- -----------

Per share................................ $23.1600 $1.0422 $22.1178
Total.................................... $79,776,010 $3,589,920 $76,186,090

Cal Dive has granted the underwriters the right to purchase up to an additional
516,684 shares of common stock to cover over-allotments.

The Securities and Exchange Commission and state securities regulators have not
approved or disapproved these securities, or determined if this prospectus is
truthful or complete. Any representation to the contrary is a criminal offense.

Morgan Stanley & Co. Incorporated expects to deliver the shares to purchasers on
May 28, 2002.
------------------------

MORGAN STANLEY SALOMON SMITH BARNEY
RAYMOND JAMES SIMMONS & COMPANY
International

May 21, 2002

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[FOLD OUT -- WITH PICTURES]

[PHOTO]

Q4000
A newbuild semi-submersible multi-service vessel which is custom designed for
well intervention and construction tasks to 10,000 feet of water. The vessel
incorporates our latest technologies, including various patented features such
as the absence of lower hull cross bracing.

[PHOTO]

UNCLE JOHN
The UNCLE JOHN is a dynamically positioned 254 foot semi-submersible,
multi-purpose support vessel with a uniquely designed derrick. The vessel is
capable of providing well intervention services and supporting full field
developments in the Deepwater Gulf of Mexico.

[PHOTO]

ECLIPSE
This large dynamically positioned monohull vessel is 370 feet long, 67 feet wide
and has recently been configured into a DP DSV by installing a saturation diving
system, restoring the ballast system and upgrading to DP-2. The ECLIPSE began
work in March 2002.

[PHOTO]

ROVs
To enable us to control critical path equipment involved in our deepwater
projects, we acquired Canyon in January 2002. Canyon currently owns 19 ROVs and
operates eight trenching systems.

[PHOTO]

CAL DIVER I
We entered the saturation diving and turnkey contracting business in 1984 with
the CAL DIVER I, which we custom-designed to be the first DSV with moonpool
deployed saturation diving systems dedicated for use in the Gulf. This 4-point
moored 196 foot vessel performs work on the Outer Continental Shelf in water
depths up to 1,000 feet.

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TABLE OF CONTENTS

[Download Table]

PAGE
----

Prospectus Summary.................... 4
Risk Factors.......................... 9
Special Note Regarding Forward-Looking
Statements.......................... 12
Use of Proceeds....................... 13
Common Stock Price Range.............. 13
Dividend Policy....................... 13
Capitalization........................ 14
Selected Historical Financial and
Operating Data...................... 15
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 17

[Download Table]

PAGE
----

The Industry.......................... 28
Business.............................. 30
Management............................ 41
Description of Capital Stock.......... 43
Underwriters.......................... 47
Legal Matters......................... 49
Experts............................... 49
Other Matters......................... 49
Where You Can Find More Information... 50
Information Incorporated by
Reference........................... 50
Index to Consolidated Financial
Statements.......................... F-1

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

You should rely only on the information contained in this prospectus. We
have not authorized anyone to provide you with information different from that
contained in this prospectus. We are offering to sell shares of common stock,
and seeking offers to buy shares of common stock, only in jurisdictions where
offers and sales are permitted. The information in this prospectus is accurate
only as of the date of this prospectus, regardless of the time of delivery of
this prospectus or of any sale of common stock.

In this prospectus, "Cal Dive," "we," "us," and "our" refer to Cal Dive
International, Inc. and, unless otherwise stated, our subsidiaries.

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PROSPECTUS SUMMARY

You should read the following summary together with the more detailed
information regarding our company and the common stock being sold in this
offering and our financial statements and notes thereto appearing elsewhere in
this prospectus.

We are a leading energy services company specializing in subsea
construction and well operations. We operate in all water depths of the Gulf of
Mexico, with services that cover the lifecycle of an offshore natural gas or oil
field. We believe we have a longstanding reputation for innovation in our subsea
construction techniques, equipment design and methods of partnering with
customers. Our diversified fleet of 23 vessels and 19 remotely operated
vehicles, or ROVs, performs services that support drilling, well completion,
intervention, 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 ourselves for work in water depths greater than 1,000
feet, referred to as the Deepwater, by assembling a technically advanced fleet
of dynamically positioned, or DP, vessels and ROVs and a highly experienced
group of support professionals. Our DP vessels serve as work platforms for
subsea solutions we provide with our alliance partners, a group of
internationally recognized contractors and manufacturers. In January 2002 we
purchased Canyon Offshore, Inc., our new ROV subsidiary that 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, the
Q4000, our newest and most advanced Deepwater semi-submersible multi-service
vessel, or MSV, incorporates our latest technologies, and elements of its design
are patented. We anticipate that the recently delivered Q4000 will improve
Deepwater well completion, intervention and construction economics for our
customers. Availability of the Q4000, two other vessels that we recently
purchased, the Eclipse and the Mystic Viking, as well as the
soon-to-be-completed Intrepid (formerly Sea Sorceress), will enable us to offer
the largest permanently deployed fleet of DP subsea construction and
intervention vessels in the Gulf.

On the Outer Continental Shelf, or 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 a full complement of
services in the shallow water market from the shore to 300 feet. Through the
acquisition of the assets of Professional Divers of New Orleans, Inc. in early
2001, we added important vessel and offshore personnel capacity. Fifteen of our
vessels are permanently dedicated to performing traditional diving services,
with another five DP vessels capable of providing such services, on the OCS.
Seven of these vessels support saturation diving. We believe we are uniquely
qualified to provide these services in the OCS "spot market" where projects are
generally turnkey in nature, short in duration (two to 30 days) and require the
availability of multiple vessels due to frequent rescheduling. The technical and
operational experience of our personnel and the scheduling flexibility offered
by our large fleet enable us to manage turnkey projects and to meet our
customers' requirements. We have also established a leading position in the
salvage market by offering customers a number of options to address their
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., or ERT, acquires and produces mature, non-core offshore
property interests, offering customers a cost-effective alternative to the
decommissioning process required by law. ERT's reservoir engineering and
geophysical expertise enabled us to acquire a working interest in Gunnison, a
Deepwater Gulf oil and natural gas exploration project, in partnership with the
operator, Kerr-McGee Oil & Gas Corporation. We anticipate that this investment
will generate significant income for us in the future and will also help secure
utilization for our subsea assets. This project has now been approved by the
operator for development, and we are participating in field development planning
and will collaborate with the other working interest owners in executing subsea
construction work. We are in the process of expanding our Production Partnering
strategy through a recently

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signed letter of intent to participate in the ownership of the production
facility for the Marco Polo field, a Deepwater Gulf natural gas and oil
exploration project operated by Anadarko Petroleum Corporation. We expect that
owning this tension-leg platform, or TLP, in a 50/50 joint venture with El Paso
Energy Partners, L.P. will generate income for us in the future and also provide
us with additional construction work and farm-in opportunities for ERT.

Our overall corporate goal is to increase shareholder value by
strengthening our market position to provide a return that leads our Peer Group.
Our return on capital employed, or ROCE, was 12% in 2001 and 16% over the past
five years, which is significantly higher than our Peer Group average. We have
been able to achieve our ROCE objective by focusing on the following business
strengths and strategies.

OUR STRENGTHS

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

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

Major Provider of Marine Construction Services on the OCS. We believe that
our expansion of Aquatica, our alliance with Horizon and our dominant position
in the Gulf for saturation diving services make us the largest supplier of
marine construction services on the OCS. We expect the ongoing depletion of
existing reserves, coupled with growing demand for natural gas, to require
increased exploitation and development of OCS reservoirs.

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

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 that make up
approximately half of the structures in the Gulf. We expect demand for
decommissioning services to increase due to the significant backlog of platforms
and caissons that must be removed in accordance with government regulations.

OUR STRATEGIES

Focusing on the Gulf. We will continue to focus on the Gulf of Mexico,
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, to increase significantly in the next several
years.

Capturing a Significant Share of the Deepwater Market. In the last 12
months, we took the opportunity to expand our fleet to service Deepwater
projects by purchasing both the Mystic Viking, to replace the Balmoral Sea with
more capacity, and the Eclipse, a large mono-hull vessel with significant deck
load capacity. In addition, we recently took delivery of the Q4000 and are near
completion of the Intrepid. When all vessels begin work, our fleet will include
eight world-class DP vessels, seven of which will be based in the Gulf of
Mexico. These seven vessels are the most any company has permanently deployed in
the Gulf and help assure scheduling flexibility for the technological challenges
of Deepwater subsea construction and well

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intervention. With this expanded fleet, we expect to benefit from the
anticipated increase in Deepwater activity.

In addition, through our Canyon acquisition, we now own 19 ROV systems and
operate eight others. Canyon represents an integration which is consistent with
our strategy of controlling all aspects along 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.

Developing Well Operations Niche. We are employing more Deepwater assets,
construction techniques and technologies focused upon servicing upstream market
niches, such as: drilling support, which includes pre-setting casings, setting
trees and commissioning wells; life of field services, which includes well
intervention; and decommissioning and abandonment. Currently there is no
cost-effective solution for subsea well operation to troubleshoot or enhance
production, shift zones or perform recompletions, as all such work today must be
done from drilling rigs. Examples of our strategic developments in this area
include the enhanced well intervention and completion designs of the Q4000 and
Uncle John.

Building Alliances to Expand the Scope of Our Services and Technology. We
have Gulf alliance agreements with the following domestic and internationally
recognized contractors and manufacturers: FMC Corp., Fugro-McClelland Marine
Geoscience, Inc., Horizon Offshore, Inc., Schlumberger Limited and Shell
Offshore, Inc. These alliances enable us to offer state-of-the-art products and
services, and allow us to provide our customers with integrated solutions
designed to minimize project duration and cost.

Maximizing the Value of Mature Natural Gas and Oil Properties. Through
ERT, we offer our customers a cost-effective alternative to the decommissioning
process. Utilizing the exploitation and development skills attained as a result
of the acquisition of decommissioning prospects, ERT is expanding its strategy
to include the acquisition of selected properties with proved undeveloped
reserves. For example, in April 2002, ERT agreed to acquire East Cameron Block
374, which includes proved undeveloped reserves. Since its inception in 1992,
ERT has delivered a 30% average annual return on its invested capital, in
substantial part through ERT's ability to nearly replace reserves by conducting
successful exploitation programs on existing properties.

Partnering with Customers. In 2000, we expanded the ERT business strategy
to Deepwater prospects through a working interest in the Gunnison project. ERT's
total proved reserves at December 31, 2001 grew to 100.0 Bcfe, including 76.5
Bcfe of initial proved reserves assigned to our ownership position in
Gunnison. In December 2001, we signed a letter of intent to form a 50/50 joint
venture with El Paso Energy Partners, L.P. to construct, install and own a TLP
production hub and associated facilities primarily for Anadarko Petroleum
Corporation's Marco Polo field discovery in the Deepwater Gulf of Mexico. We
expect our participation in these projects, and potentially others in the
future, to contribute to future vessel utilization and increase our visibility
in the market.

CORPORATE INFORMATION

We were organized under the laws of Minnesota in 1990. Our principal
executive offices are located at 400 N. Sam Houston Parkway E., Suite 400,
Houston, Texas 77060, and our telephone number is (281) 618-0400.

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THE OFFERING

Common stock offered........................ 3,444,560 shares

Common stock to be outstanding after the
offering.................................... 36,730,487 shares

Use of proceeds............................. For general corporate purposes,
including repaying debt,
identified capital expenditures
and possible acquisitions of and
investments in complementary
businesses or assets.

Nasdaq National Market symbol............... CDIS

The common stock outstanding after the offering is based on the number of
shares outstanding as of May 2, 2002 and excludes 3,328,593 shares of common
stock reserved for issuance under our stock plans, of which 1,801,330 shares are
issuable upon exercise of outstanding options at a weighted average price of
$17.69 per share.

In addition, we may sell up to 516,684 shares pursuant to the underwriters'
over-allotment option. If the over-allotment option is exercised in full, we
will receive total net proceeds of approximately $87.3 million.

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SUMMARY HISTORICAL FINANCIAL AND OPERATING DATA

The following summary financial and operating data is qualified in its
entirety by the more detailed information appearing in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and our
consolidated financial statements, including the notes thereto, appearing
elsewhere in this prospectus.

[Enlarge/Download Table]

THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED MARCH 31,
---------------------------------------------------- -------------------
1997 1998 1999 2000 2001 2001 2002
-------- -------- -------- -------- -------- -------- --------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

INCOME STATEMENT DATA:
Net revenues:
Subsea and salvage...................... $ 92,860 $139,310 $128,435 $110,217 $163,740 $ 31,282 $ 44,370
Natural gas and oil production.......... 16,526 12,577 32,519 70,797 63,401 27,200 9,558
-------- -------- -------- -------- -------- -------- --------
Total revenues............................ 109,386 151,887 160,954 181,014 227,141 58,482 53,928
Gross profit.............................. 33,685 49,209 37,251 55,369 66,911 22,258 11,118
Income from operations.................... 22,489 33,408 24,024 34,569 45,586 16,651 4,812
Income before income taxes................ 22,281 37,144 25,473 34,015 44,296 16,360 4,616
Net income................................ 14,482 24,125 16,899 23,326 28,932 10,774 3,001
Diluted net income per share.............. $ .54 $ .81 $ .55 $ .72 $ .88 $ .33 $ .09
BALANCE SHEET DATA (AT END OF PERIOD):
Cash and cash equivalents................. $ 12,842 $ 32,380 $ 11,310 $ 44,838 $ 37,123 $ 56,693 $ 4,103
Restricted cash........................... 183 463 8,686 2,624 -- 2,654 --
Working capital........................... 28,927 45,916 38,887 76,381 48,601 71,221 37,871
Total assets.............................. 125,600 164,235 243,722 347,488 473,122 363,174 555,462
Long-term debt............................ -- -- -- 40,054 98,048 40,054 163,920
Shareholders' equity...................... 89,369 113,643 150,872 194,725 226,349 207,729 237,151
OTHER FINANCIAL DATA:
EBITDA(1)................................. $ 29,916 $ 45,544 $ 44,805 $ 65,085 $ 78,962 $ 26,890 $ 10,954
Depreciation and amortization............. 7,512 9,563 20,615 30,730 34,533 10,394 6,313
Capital expenditures...................... 28,936 14,886 77,447 95,124 151,261 19,655 35,712
OPERATING DATA:
Number of vessels (at end of period):
DP MSVs................................. 1 1 1 2 2 2 2
DP DSVs................................. 3 3 4 3 6(2) 3 6(2)
DSVs.................................... 5 5 7 14 14 14 14
Derrick barge........................... 2 2 2 1 1 1 1
-------- -------- -------- -------- -------- -------- --------
Total vessels....................... 11 11 14 20 23 20 23
Natural gas and oil properties:
Properties acquired..................... 2 4 22 7 2 -- --
Properties sold or abandoned............ 2 2 3 2 -- -- --
Total properties (at end of
period)(3)........................ 14 16 35 40 42 40 42
Natural gas and oil production:
Gas (Mmcf).............................. 5,385 4,535 6,819 14,959 9,473 3,142 1,930
Oil (MBbls)............................. 51 67 339 739 743 191 163
Estimated proved reserves (at end of
period)(4):
Natural gas (Mmcf)...................... 22,245 22,434 25,381 21,711 53,936 18,569 54,057
Oil and condensate (MBbls).............. 200 70 1,702 1,081 7,858 890 7,702
Standardized measure of discounted future
net cash flows(4)(5).................... $ 19,760 $ 10,156 $ 22,843 $ 77,713 $ 21,445 N/A N/A

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

(1) As used herein, EBITDA represents earnings before net interest and other
expense, taxes, depreciation and amortization. EBITDA is frequently used by
securities analysts and is presented here to provide additional information
about our operations. EBITDA should not be considered as an alternative to
net income, as an indicator of our operating performance or as an
alternative to cash flow as a better measure of liquidity.

(2) Includes a leased vessel which is under construction and should be available
in June 2002.

(3) As of December 31, 2001, we owned (not including Gunnison) an interest in
122 gross (102 net) natural gas wells and 104 gross (79 net) oil wells
located in the Gulf.

(4) The reserves assigned to Gunnison, which constitute over 75% of our reported
proved reserves as of December 31, 2001 and March 31, 2002, were computed as
15% of the reserves reported by the operator. The remainder of our year-end
reserves are based on annual estimates reviewed by Miller and Lents, Ltd.

(5) 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.

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RISK FACTORS

You should carefully consider the following risk factors and all other
information contained in this prospectus before investing in our common stock.
Investing in our common stock involves a high degree of risk. Any of the
following factors could harm our business and future operating results and could
result in a partial or complete loss of your investment.

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

Our business is substantially dependent upon the condition of the natural
gas and oil industry and, in particular, the willingness of natural gas and oil
companies to make capital expenditures for offshore exploration, drilling and
production operations. The level of capital expenditures generally depends on
the prevailing view of future natural gas and oil prices, which are influenced
by numerous factors affecting the supply and demand for natural gas and oil,
including:

-- worldwide economic activity,

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

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

-- the cost of exploring for and producing natural gas and oil,

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

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

-- technological advances,

-- interest rates and the cost of capital,

-- environmental regulations, and

-- tax policies.

The level of offshore construction activity has not increased materially
despite high commodity prices in the first half of 2001 and more normalized
prices in the second half of 2001 and early 2002. We cannot assure you that
activity levels will increase anytime soon. A sustained period of low drilling
and production activity or the return of low commodity prices would likely have
a material adverse effect on our financial position and results of operations.

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

Marine construction involves a high degree of operational risk. Hazards,
such as vessels sinking, grounding, colliding and sustaining damage from severe
weather conditions, are inherent in marine operations. These hazards can cause
personal injury or loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.
Damage arising from such occurrences may result in lawsuits asserting large
claims. We maintain such insurance protection as we deem prudent, including
Jones Act employee coverage, which is the maritime equivalent of workers'
compensation, and hull insurance on our vessels. We cannot assure you that any
such insurance will be sufficient or effective under all circumstances or
against all hazards to which we may be subject. A successful claim for which we
are not fully insured could have a material adverse effect on us. Moreover, we
cannot assure you that we will be able to maintain adequate insurance in the
future at rates that we consider reasonable. As a result of market conditions,
premiums and deductibles for certain of our insurance policies have increased
substantially, and could escalate further. In some instances, certain insurance
could become unavailable or available only for reduced amounts of coverage. For
example, insurance carriers are now requiring broad exclusions for losses due to
war risk and terrorist acts. As construction activity moves into deeper water in
the Gulf, construction projects tend to become larger and more complex than
shallow water projects. As a result, our revenues and profits are increasingly
dependent on our larger vessels. The current insurance on our vessels, in some
cases, in
9

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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 were to lose 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, our results in any one quarter
are not necessarily indicative of annual results or continuing trends.

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

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

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

Our proved reserves at December 31, 2001 included the initial reserves
assigned to our ownership position in Gunnison, which constitute over 75% of our
reported proved reserves as of that date. The reserves assigned to Gunnison were
not prepared by us or reviewed by our reservoir engineers, as we do not own the
seismic data for the three fields that comprise Gunnison. Instead, they were
computed as 15% of the reserves reported by the operator, Kerr-McGee Oil & Gas
Corporation and we have been advised that Kerr-McGee's estimate was prepared by
its internal reservoir engineering staff. This prospectus also contains
estimates of our other proved natural gas and oil reserves and the estimated
future net cash flows therefrom based upon reports for the years ended December
31, 1997, 1998, 1999, 2000 and 2001, reviewed by Miller and Lents, Ltd.,
independent petroleum engineers. These reports rely 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 prospectus 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.

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

The Gunnison project 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
10

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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. We have a synthetic lease facility to provide for the financing of
our portion of the construction costs of the spar, with current commitments of
$67.0 million, of which we had drawn down $12.1 million as of March 31, 2002.
This facility has yet to be syndicated. We are working with the agent to modify
the facility and are discussing the conversion of the facility to a term loan in
a reduced amount. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."

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

The Q4000 has recently been placed into service and the Intrepid is
scheduled to be placed into service during the second quarter of 2002. We will
not receive any material increase in revenue or cash flow from their operation
until there is significant utilization of the vessels. We cannot assure you that
customer demand for these vessels will be as high as currently anticipated and,
as a result, our future cash flows may be adversely affected. New vessels from
third parties may also enter the market in the coming years and compete with the
Q4000 and the Intrepid 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 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. 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 AND RETAIN OTHER HIGHLY QUALIFIED PERSONNEL IN THE FUTURE, COULD DISRUPT
OUR OPERATIONS AND ADVERSELY AFFECT OUR FINANCIAL RESULTS.

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

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

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

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

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

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

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.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus and the documents incorporated by reference include 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 under "Risk Factors" 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 "Risk
Factors" and elsewhere in this prospectus could have a material adverse effect
on our business, results of operations and financial position.

424B4 13th Page of 76 TOC 1st Previous Next ↓Bottom Just 13th
USE OF PROCEEDS

We estimate that the net proceeds from our sale of the 3,444,560 shares of
common stock in this offering will be approximately $75.9 million, after
deducting underwriting discounts and commissions and estimated offering expenses
payable by us.

We expect to use the net proceeds from the offering for general corporate
purposes, including repaying debt, identified capital expenditures and possible
acquisitions of and investments in complementary businesses or assets. We
currently have no agreement or understanding regarding any acquisition or
investment. Pending these uses, we intend to invest the net proceeds from the
offering in short-term instruments or apply them to reduce borrowings under our
revolving credit facility. This facility, which matures in February 2005, is
collateralized by accounts receivable and most of the vessel fleet and bears
interest at LIBOR plus 125-250 basis points depending on our leverage ratios. As
of April 30, 2002, the interest rate under the revolving credit facility was
4.5%. For risks associated with our use of proceeds, see "Risk Factors."

COMMON STOCK PRICE RANGE

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

[Download Table]

COMMON STOCK
PRICE
---------------
HIGH LOW
------ ------

CALENDAR YEAR 2000
First quarter............................................. $25.38 $18.00
Second quarter............................................ 27.09 23.03
Third quarter............................................. 28.75 24.13
Fourth quarter............................................ 26.63 19.63
CALENDAR YEAR 2001
First quarter............................................. $31.00 $22.00
Second quarter............................................ 30.66 21.88
Third quarter............................................. 23.04 15.98
Fourth quarter............................................ 25.86 16.01
CALENDAR YEAR 2002
First quarter............................................. $25.20 $20.50
Second quarter (through May 21, 2002)..................... $27.22 $23.16

The prices for periods prior to November 13, 2000 have been adjusted to
give retroactive effect to a 2-for-1 stock split as of that date. On May 21,
2002, the closing sale price of our common stock on the Nasdaq National Market
was $23.16 per share. As of March 31, 2002, there were an estimated 3,971
beneficial holders of our common stock.

DIVIDEND POLICY

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

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CAPITALIZATION

The following table sets forth our cash position and capitalization as of
March 31, 2002 on both an actual basis and an as adjusted basis to give effect
to our sale in this offering of 3,444,560 shares of common stock, after
deducting underwriting discounts and commissions and estimated offering
expenses, and the application of the estimated net proceeds of this offering of
$75.9 million. You should read this information in conjunction with our
consolidated financial statements and the related notes thereto beginning on
page F-1 of this prospectus.

[Download Table]

AS OF MARCH 31, 2002
----------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)

Cash and cash equivalents................................... $ 4,103 $ 34,117
======== ========
Short-term debt............................................. $ 4,550 $ 4,550
-------- --------
Revolving credit facility................................... 45,862 --
MARAD debt.................................................. 112,661 112,661
Other long-term debt........................................ 5,397 5,397
-------- --------
Total long-term debt...................................... 163,920 118,058
-------- --------
Total debt............................................. 168,470 122,608
Shareholders' equity:
Common stock, no par value; 120,000 shares authorized;
46,837 shares issued, actual; 50,282 shares issued, as
adjusted............................................... 104,332 180,208
Retained earnings......................................... 136,571 136,571
Treasury stock, 13,602 shares............................. (3,752) (3,752)
-------- --------
Total shareholders' equity........................... 237,151 313,027
-------- --------
Total capitalization............................ $405,621 $435,635
======== ========

The information set forth above does not include an aggregate of 3,328,593
shares of common stock reserved for issuance under our stock plans of which
1,801,330 shares of common stock are issuable upon exercise of outstanding stock
options at a weighted average price of $17.69 per share and assumes no exercise
of the underwriters' over-allotment option. The table above also does not
include $12.1 million of project financing guaranteed by Cal Dive with respect
to the Gunnison project. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The historical financial data presented in the table below for and at the
end of each of the years in the five-year period ended December 31, 2001 are
derived from our consolidated financial statements audited by Arthur Andersen
LLP, independent public accountants. The historical financial data presented in
the table below for and at the end of each of the three-month periods ended
March 31, 2002 and 2001 are derived from our unaudited consolidated condensed
financial statements. In the opinion of our management, such unaudited
consolidated condensed financial statements include all adjustments (consisting
of normal recurring adjustments) necessary for a fair presentation of the
financial data for such periods. The results for the three months ended March
31, 2002 and 2001 are not necessarily indicative of the results to be achieved
for the full year. The data should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
our consolidated financial statements, including the notes thereto, appearing
elsewhere in this prospectus.

[Enlarge/Download Table]

INCOME STATEMENT DATA:
Net revenues:
Subsea and salvage...................... $ 92,860 $139,310 $128,435 $110,217 $163,740 $ 31,282 $ 44,370
Natural gas and oil production.......... 16,526 12,577 32,519 70,797 63,401 27,200 9,558
-------- -------- -------- -------- -------- -------- --------
Total revenues............................ 109,386 151,887 160,954 181,014 227,141 58,482 53,928
-------- -------- -------- -------- -------- -------- --------
Cost of sales:
Subsea and salvage...................... 67,538 93,607 103,113 94,104 127,047 25,170 37,690
Natural gas and oil production.......... 8,163 9,071 20,590 31,541 33,183 11,054 5,120
-------- -------- -------- -------- -------- -------- --------
Gross profit.............................. 33,685 49,209 37,251 55,369 66,911 22,258 11,118
-------- -------- -------- -------- -------- -------- --------
Selling and administrative expenses:
Subsea and salvage...................... 8,911 14,312 9,504 13,930 15,044 3,090 5,214
Natural gas and oil production.......... 2,285 1,489 3,723 6,870 6,281 2,517 1,092
-------- -------- -------- -------- -------- -------- --------
Income from operations.................... 22,489 33,408 24,024 34,569 45,586 16,651 4,812
Other income and expenses:
Equity in earnings of Aquatica.......... -- 2,633 600 -- -- -- --
Net interest (income) expense and
other................................. 208 (1,103) (849) 554 1,290 291 196
-------- -------- -------- -------- -------- -------- --------
Income before income taxes................ 22,281 37,144 25,473 34,015 44,296 16,360 4,616
Provision for income taxes................ 7,799 13,019 8,465 11,555 15,504 5,726 1,615
Minority interest......................... -- -- 109 (866) (140) (140) --
-------- -------- -------- -------- -------- -------- --------
Net income................................ $ 14,482 $ 24,125 $ 16,899 $ 23,326 $ 28,932 $ 10,774 $ 3,001
======== ======== ======== ======== ======== ======== ========
Net income per share:
Basic................................... $ .56 $ .83 $ .56 $ .74 $ .89 $ .33 $ .09
Diluted................................. .54 .81 .55 .72 .88 .33 .09
Weighted average common shares
outstanding:
Basic................................... 25,766 29,098 30,016 31,588 32,449 32,308 32,648
Diluted................................. 26,626 29,928 30,654 32,341 33,055 33,072 32,932
BALANCE SHEET DATA (AT END OF PERIOD):
Cash and cash equivalents............... $ 12,842 $ 32,380 $ 11,310 $ 44,838 $ 37,123 $ 56,693 $ 4,103
Restricted cash......................... 183 463 8,686 2,624 -- 2,654 --
Working capital......................... 28,927 45,916 38,887 76,381 48,601 71,221 37,871
Total assets............................ 125,600 164,235 243,722 347,488 473,122 363,174 555,462
Long-term debt.......................... -- -- -- 40,054 98,048 40,054 163,920
Shareholders' equity.................... 89,369 113,643 150,872 194,725 226,349 207,729 237,151
OTHER FINANCIAL DATA:
EBITDA(1)............................... $ 29,916 $ 45,544 $ 44,805 $ 65,085 $ 78,962 $ 26,890 $ 10,954
Depreciation and amortization........... 7,512 9,563 20,615 30,730 34,533 10,394 6,313
Capital expenditures.................... 28,936 14,886 77,447 95,124 151,261 19,655 35,712
Net cash provided by (used in):
Operating activities.................. 22,294 35,697 25,499 53,701 89,107 40,467 (10,646)
Investing activities.................. (28,288) (16,491) (48,612) (77,994) (157,825) (30,403) (85,451)
Financing activities.................. 18,815 149 2,043 57,821 61,003 1,791 63,077

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[Enlarge/Download Table]

OPERATING DATA:
Number of vessels (at end of period):
DP MSVs................................. 1 1 1 2 2 2 2
DP DSVs................................. 3 3 4 3 6(2) 3 6(2)
DSVs.................................... 5 5 7 14 14 14 14
Derrick barge........................... 2 2 2 1 1 1 1
-------- -------- -------- -------- -------- -------- --------
Total vessels....................... 11 11 14 20 23 20 23
Natural gas and oil properties:
Properties acquired..................... 2 4 22 7 2 -- --
Properties sold or abandoned............ 2 2 3 2 -- -- --
Total properties (at end of
period)(3)........................ 14 16 35 40 42 40 42
Natural gas and oil properties:
Gas (Mmcf).............................. 5,385 4,535 6,819 14,959 9,473 3,142 1,930
Oil (MBbls)............................. 51 67 339 739 743 191 163
Estimated proved reserves (at end of
period)(4):
Natural gas (Mmcf)...................... 22,245 22,434 25,381 21,711 53,936 18,569 54,057
Oil and condensate (MBbls).............. 200 70 1,702 1,081 7,858 890 7,702
Standardized measure of discounted future
net cash flows(4)(5).................... $ 19,760 $ 10,156 $ 22,843 $ 77,713 $ 21,445 N/A N/A

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

(1) As used herein, EBITDA represents earnings before net interest and other
expense, taxes, depreciation and amortization. EBITDA is frequently used by
security analysts and is presented here to provide additional information
about our operations. EBITDA should not be considered as an alternative to
net income, as an indicator of our operating performance or as an
alternative to cash flow as a better measure of liquidity.

(2) Includes a leased vessel which is under construction and should be available
in June 2002.

(3) As of December 31, 2001, we owned (excluding our interest in Gunnison) an
interest in 122 gross (102 net) natural gas wells and 104 gross (79 net) oil
wells located in the Gulf.

(5) 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.

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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 we use 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. In
the second quarter of 1999, oil prices reached their highest levels since the
Gulf War and natural gas prices reached $10.00 per Mcf in early 2001, pushing
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, resulting in offshore mobile rig
utilization rates dropping to approximately 70%. Our primary leading indicator,
the number of offshore mobile rigs contracted, is currently at approximately 120
rigs employed in the Gulf of Mexico, compared to 180 during the first quarter of
2001. The Deepwater Gulf is principally being developed for oil, with the
complexity of developing these reservoirs resulting in significant lead times to
first production. We are currently tracking 30 fields that we expect 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 subsea construction and well intervention 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 sellers' potential
abandonment liabilities are a significant consideration with respect to the
offshore properties we have purchased to date. Although higher natural gas
prices tend to reduce the number of mature properties available for sale, these
higher prices typically contribute to improved operating results for ERT, 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 for sale. We have expanded the scope of our gas and oil operations by
taking a working interest in Gunnison, a Deepwater Gulf development of
Kerr-McGee Oil & Gas Corporation which has discovered significant reserves. We
are also expanding our Deepwater hub strategy through our recently signed letter
of intent 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 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 natural gas and oil 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.

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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.

[Enlarge/Download Table]

1999 2000 2001
--------------------------------- --------------------------------- ------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------

U.S. natural gas prices(1)....... $ 1.80 $ 2.22 $ 2.53 $ 2.45 $ 2.52 $ 3.47 $ 4.27 $ 5.29 $ 7.09 $ 4.67 $ 2.88
ERT natural gas and oil
production
(Mmcfe)......................... 1,488 1,803 2,777 2,786 3,321 4,169 4,271 3,725 4,290 3,552 3,289
Rigs under contract in the
Gulf(2)......................... 121 115 126 146 148 160 175 178 182 189 165
Platform installations(3)........ 12 13 13 16 9 19 27 19 12 19 20
Platform removals(3)............. 2 20 40 15 -- 25 61 7 13 11 19
Our average vessel utilization
rate:(4)
DP.............................. 70% 49% 82% 69% 71% 38% 45% 56% 61% 76% 85%
Saturation DSV.................. 54 69 79 65 57 57 78 60 72 67 82
Surface diving.................. 63 69 78 51 31 58 55 57 61 81 72
Derrick barge................... 40 68 83 50 8 41 53 59 30 54 67

2001 2002
------ ------
Q4 Q1
------ ------

U.S. natural gas prices(1)....... $ 2.45 $ 2.32
ERT natural gas and oil
production
(Mmcfe)......................... 2,797 2,918
Rigs under contract in the
Gulf(2)......................... 125 122
Platform installations(3)........ 11 N/A
Platform removals(3)............. 16 4
Our average vessel utilization
rate:(4)
DP.............................. 95% 92%
Saturation DSV.................. 91 45
Surface diving.................. 60 58
Derrick barge................... 47 --

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

(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.

CRITICAL ACCOUNTING POLICIES

Our results of operations and financial condition, as reflected in the
accompanying financial statements and related footnotes, are subject to
management's evaluation and interpretation of business conditions, changing
capital market conditions and other factors which could affect the ongoing
viability of our business segments and/or our customers. We believe the most
critical accounting policies in this regard are the estimation of revenue
allowance on gross amounts billed and evaluation of recoverability of property
and equipment and goodwill balances. While these issues require us to make
judgments that are somewhat subjective, they are generally based on a
significant amount of historical data and current market data. Another area
which requires us to make subjective judgments is that of revenue recognition.
Our 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. We recognize 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, we perform detailed
estimating procedures, including engineering studies. We follow the successful
efforts method of accounting for our 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.

In March 2002 and April 2002, ERT entered into swap contracts that require
payments to, or receipts from, an energy trading company based on the difference
between a fixed and a variable price for a

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commodity. The payments under these contracts will be based on 1,464,000 Mmbtu
of natural gas at a fixed price of $3.46/Mcf over six months and 100,800 Bbls of
oil at an average fixed price of $25.87/Bbl over six months. We believe these
levels represent approximately one-third of ERT's production over the next six
months. Under SFAS No. 133, we account for these transactions as speculative and
record the transactions as assets or liabilities, as applicable, and record any
gain or loss on settled transactions, and the change in market value, of
unsettled positions at the end of each reporting period in our consolidated
statement of operations. The impact of the swap contracts for the quarter ended
March 31, 2002 was immaterial to the financial statements.

NEW ACCOUNTING PRONOUNCEMENTS

In July 2001, the Financial Accounting Standards Board, or FASB, issued
Statement of Financial Accounting Standards, or SFAS, No. 141, Business
Combinations, which supersedes Accounting Principles Board, or 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 are effective for
transactions accounted for using the purchase method completed after June 30,
2001. The only business combination we completed subsequent to June 30, 2001 was
our acquisition of Canyon in January 2002 which was accounted for using the
purchase method in accordance with SFAS 141.

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, applies to
goodwill and intangible assets arising from transactions completed before and
after the statement's effective date. We adopted this standard effective January
1, 2002, the effect of which was immaterial to our financial position and
results of operations.

In July 2001, the FASB released SFAS No. 143, Accounting for Asset
Retirement Obligations, which we are required to adopt no later than January 1,
2003. SFAS 143 addresses the financial accounting and reporting obligations and
retirement costs related to the retirement of tangible long-lived assets. We are
currently reviewing the provisions of SFAS 143 to determine the standard's
impact, if any, on our financial statements upon adoption. Among other things
SFAS 143 will require oil and gas companies to reflect decommissioning
liabilities on the face of the balance sheet, which 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 us beginning January 1,
2002. SFAS 144 supersedes SFAS 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 No. 30. We adopted this standard effective January 1, 2002, the effect
of which was immaterial to our financial position and results of operations.

RESULTS OF OPERATIONS

COMPARISON OF THREE MONTHS ENDED MARCH 31, 2002 AND 2001

Revenues. During the three months ended March 31, 2002, our revenues
decreased 8% to $53.9 million compared to $58.5 million for the three months
ended March 31, 2001. The decrease was attributable to the Natural Gas and Oil
Production segment, offset partially by the contributions from Canyon, which we
acquired January 4, 2002. Subsea and Salvage segment revenue increased $13.1
million to $44.4 million in the first quarter of 2002 compared to $31.3 million
for the comparable prior-year period due mainly to Canyon's $11.4 million of
revenue and the introduction of the Eclipse.

Natural Gas and Oil Production revenue for the three months ended March 31,
2002 decreased $17.6 million to $9.6 million from $27.2 million during the
comparable prior year period. The decrease was

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due to a decline in our average realized commodity prices from $6.00 per Mcfe
($6.50 per Mcf of natural gas and $27.30 per barrel of oil) in the first quarter
of 2001 to $2.86 per Mcfe ($2.55 per Mcf of natural gas and $20.44 per barrel of
oil) in the first quarter of 2002 coupled with lower levels of production (2.9
Bcfe in the first quarter of 2002, versus 4.3 Bcfe in the comparable quarter of
2001).

Gross Profit. Gross profit of $11.1 million for the first quarter of 2002
represented a 50% decrease compared to the $22.3 million recorded in the
comparable prior year period due mainly to the revenue decrease in Natural Gas
and Oil Production described above. Natural Gas and Oil Production gross profit
decreased $11.7 million from $16.1 million in the first quarter of 2001 to $4.4
million for the three months ended March 31, 2002, due to the decreases in
average natural gas prices and production described above.

Gross margins also declined from 38% during the first quarter of 2001 to
21% during the first quarter of 2002. The gross margin decrease was due mainly
to Natural Gas and Oil Production margins declining 13 points to 46% for the
three months ended March 31, 2002 from 59% during the comparable prior year
period due to the natural gas price decline discussed above. Gross margins for
Subsea and Salvage also decreased from 20% during the first quarter of 2001 to
15% for the first quarter of 2002 due primarily to low margins on the
Nansen/Boomvang project, which included a high level of pass-through revenues,
and softened demand for services on the OCS during the first quarter 2002
compared to the comparable quarter in 2001.

Selling and Administrative Expenses. Selling and administrative expenses
were $6.3 million in the first quarter of 2002, which is 12% more than the $5.6
million incurred in the first quarter of 2001 due to the addition of Canyon's
selling and administrative expenses.

Net Interest (Income) Expense and Other. We reported net interest expense
and other of $196,000 for the three months ended March 31, 2002, compared to the
$291,000 recorded for the three months ended March 31, 2001. We capitalized $1.3
million of interest during the first quarter of 2002 compared to $100,000
capitalized during the first quarter of 2001, which relates to construction of
the Q4000 and the Intrepid conversion.

Income Taxes. Income taxes decreased to $1.6 million for the three months
ended March 31, 2002 compared to $5.7 million in the comparable prior year
period due to decreased profitability. Our effective tax rate was 35% for the
three months ended March 31, 2002 and 2001.

Net Income. Net income of $3.0 million for the three months ended March
31, 2002 was $7.8 million, or 72%, less than the comparable period in 2001 as a
result of the factors described above.

COMPARISON OF YEARS ENDED DECEMBER 31, 2001 AND 2000

Revenues. During the year ended December 31, 2001, our 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 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 our improved market share,
an expansion in the scope of Deepwater services provided and expansion into
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
barrel for oil during 2001 compared to $4.04 per Mcf and $28.91 per barrel 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 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

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year ended December 31, 2001 due mainly to the increase in utilization resulting
from increased marine construction activity, even though we earned only 5%
margins on $15 million of revenues related to our work on the Nansen/Boomvang
field that was mostly pass-through revenue.

Natural Gas and Oil Production gross profit decreased $9.1 million to $30.2
million for the year ended December 31, 2001 from $39.3 million in the year
ended December 31, 2000 due mainly to the 10% decline in production described
above, 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 a 3% increase from the $20.8 million
incurred during 2000. These expenses as a percentage of total revenues decreased
to 9% in 2001 from 11% in 2000 principally as a result of increased revenues and
cost controls.

Net Interest (Income) Expense and Other. We 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 our 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 Q4000 construction costs. Tax refunds in this amount
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 YEARS 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 Gulf 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 and American Bureau of
Shipping, or 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 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 a result of reduced demand.

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 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 $4.04 per
Mcf in

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2000, an increase of $1.68, or 71%, over 1999. Oil prices averaged $28.91 per
barrel and oil production represented 27% of gas and oil revenues in 2000.

Gross Profit. Gross profit of $55.4 million for 2000 was 49% greater 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 to 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 Cal Dive Aker Dove accounted
for 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 low 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 production and commodity pricing improvements described
above.

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, which represented a $3.1 million increase, and to
the consolidation of Aquatica, which represented a $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 our capital program, primarily the Q4000 vessel
construction, combined with the recording of goodwill amortization expense
beginning in August 1999 upon acquiring the 55% of Aquatica that we did not
already own. Minority interest included $866,000 in 2000 compared to a $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 31%, reflecting 1,392,000 shares issued to acquire the 55% of
Aquatica that we did not already own in the third quarter of 1999 and the
610,000 shares we sold in conjunction with a public offering of shares by a
former significant shareholder during the third quarter of 2000.

LIQUIDITY AND CAPITAL RESOURCES

During the three years following our initial public offering in 1997, our
internally generated cash flow funded approximately $164 million of capital
expenditures and enabled us to remain essentially debt-free. During the third
quarter of 2000 we closed a $138.5 million long-term MARAD financing for
construction of the Q4000, and we have drawn $114.5 million on this facility
through March 31, 2002. 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. 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 March 31, 2002, we have funded over
$158 million of the 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,
the Eclipse and Professional Divers, while maintaining cash balances of $37.1
million as of December 31, 2001. In January 2002, we purchased Canyon, a
supplier of ROVs and robotics to the offshore construction and
telecommunications industries. We purchased approximately 85% of

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Canyon's stock for cash of $52.9 million, the assumption of $9.0 million of
Canyon debt, offset by $3.1 million of cash acquired, and 181,000 shares of our
common stock, 143,000 shares of which we purchased during the fourth quarter of
2001. We committed to purchase the remaining 15% for cash at a price to be
determined by Canyon's performance during the years 2002 through 2004, a portion
of which could be compensation expense. These remaining shares have been
classified as redeemable stock in subsidiary in the accompanying balance sheet
and will be adjusted to their estimated redemption value at each reporting
period prior to redemption based on Canyon's performance. As of April 30, 2002,
we had $114.5 million of debt outstanding under the MARAD facility and $39.5
million of debt outstanding under our $60 million revolving credit facility. In
addition, as of April 30, 2002, we, through a special purpose entity, had drawn
$13.6 million on a project financing facility covering our share of costs for
the construction of the spar production facility at Gunnison. We believe that
internally-generated cash flow, borrowings under existing credit facilities and
use of project financings along with other debt and equity alternatives will
provide the necessary capital to achieve our planned growth.

Operating Activities. Net cash used in operating activities was $10.6
million during the three months ended March 31, 2002, as compared to net cash
provided by operating activities of $40.5 million during the first three months
of 2001. This decrease was due mainly to decreased profitability, collection of
a $10 million tax refund during the first quarter of 2001 from the Internal
Revenue Service relating to the deduction of Q4000 construction costs as
research and development expenditures for federal tax purposes, as well as a
$25.3 million decrease in accounts payable/accrued liabilities during the first
quarter of 2002 resulting primarily from timing of payments on the
Nansen/Boomvang project and continued payments for the vessels under
construction.

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 the $10 million tax
refund referred to above. Timing of accounts payable payments provided $22.3
million of the increase due mainly to expenses accrued at December 31, 2001
relating to our work on the Nansen/ Boomvang field 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. 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 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 deferred tax increase
described above, 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 and conversion of the Intrepid; acquisitions of
Aquatica, Professional Divers and Canyon; improvements to existing vessels and
the acquisition of offshore natural gas and oil properties. As a result of our
anticipation of a significant acceleration in Deepwater demand over the next
several years, we incurred $85.5 million of capital expenditures (including the
acquisition of Canyon) during the first quarter of 2002, $151.3 million during
2001, $95.1 million during 2000 and $77.4 million during 1999.

We incurred $35.7 million of capital expenditures during the first three
months of 2002 compared to $19.7 million during the comparable prior year
period. Included in the capital expenditures during the first quarter of 2002
was $20.6 million for the construction of the Q4000 and $7.8 million relating to
the Intrepid

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DP conversion and Eclipse upgrade. Included in the $19.7 million of capital
expenditures in the first three months of 2001 was $9.2 million for the
construction of the Q4000 and $6.2 million relating to the Intrepid conversion
project.

In January 2002, we purchased Canyon. We purchased approximately 85% of
Canyon's stock for cash of $52.9 million, the assumption of $9.0 million of
Canyon debt, offset by $3.1 million of cash acquired, and 181,000 shares of our
common stock, 143,000 shares of which we purchased during the fourth quarter of
2001. We committed to purchase the remaining 15% for cash at a price to be
determined by Canyon's performance during the years 2002 through 2004, a portion
of which could be compensation expense. These remaining shares have been
classified as redeemable stock in subsidiary in the accompanying balance sheet
and will be adjusted to their estimated redemption value at each reporting
period prior to redemption based on Canyon's performance. The acquisition was
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 of $45.1 million being recorded as goodwill.

In March 2001, we acquired substantially all of the assets of Professional
Divers 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 $2.8 million balance of the
purchase price being recorded as goodwill.

Included in the $151.3 million of capital expenditures we made 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. 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 ranging from 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 in the Gulf for $2.5
million from an investment partnership composed of Cal Dive 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
$3.1 million, $4.2 million and $19.5 million, 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, or MMS. Royalty fees paid
totaled approximately $15.2 million, $11.7 million and $4.0 million for the
years 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 $3.0
million, the MMS has allowed us 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 project of Kerr-McGee Oil & Gas Corporation. Consistent with our
philosophy of avoiding exploratory risk, financing for the exploratory costs,
initially estimated at $15 million, was provided by an investment partnership,
the investors of which are Cal Dive senior management, in exchange for a 25%
revenue override of our 20% working interest. We provided no guarantees to the
investment partnership. At that time, the board of
24

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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 such a reserve level, and a
Cal Dive 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 project) and encountered
significant potential reserves resulting in the achievement of the three
criteria 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 a commercial discovery
being approved for development, we will fund our 20% share of ongoing
development and production costs estimated in a range of $100 million to $110
million, $24.6 million of which had been incurred by March 31, 2002, with over
half of that for construction of the spar production facility. We have received
a commitment from a financial institution to provide construction funding for
the spar production facility, including an option for us to convert this loan
facility into a 20-year leveraged lease after the spar is placed in service.

As part of the process of obtaining funding for the exploratory costs of
the Gunnison project 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 Cal Dive 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 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 of 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.

In December 1999, a Cal Dive-controlled company entered into a
sale-leaseback of the Cal Dive Aker Dove with Aker Maritime ASA. 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 a
significant division of Aker enabled us to "put" our interest in this affiliated
company back to Aker in return for Aker assuming all of our 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, we
closed a $138.5 million long-term financing for construction of the Q4000. 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, we made an initial draw
of $40.1 million toward construction costs. During 2001, we borrowed $59.5
million on this facility and during the first quarter of 2002 drew another $14.9
million. 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 Cal Dive guaranteeing
50% of the debt, and bears an interest rate which currently floats at a rate
approximating AAA Commercial Paper yields plus 20 basis points (2.50% as of
March 31, 2002). For a period up to two years from delivery of the vessel in
April 2002 we have options to lock in a fixed rate. In accordance with the MARAD
debt agreements, we are required to comply with certain covenants and
restrictions, including the maintenance of minimum net worth and debt-to-equity
requirements. As of March 31, 2002, we were in compliance with these covenants.

Since April 1997, we have had a $40 million revolving credit facility. We
drew upon this facility only 134 days during the four years ended December 31,
2001 with maximum borrowing of $11.9 million. We had no outstanding balance
under this facility as of December 31, 2001. In February 2002, we amended this

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facility, expanding the amount available to $60 million and extending the term
to February 2005. We had $45.9 million outstanding under this facility as of
March 31, 2002. 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 our leverage ratios and, among other restrictions, includes
financial covenants relating to cash flow leverage, minimum interest coverage
and fixed charge coverage. We were in compliance with these covenants as of
March 31, 2002.

In November 2001, ERT, with a corporate guarantee by Cal Dive, entered into
a five-year lease transaction with a special purpose entity owned by a third
party to fund our $67.0 million portion of the construction costs of the spar
production facility 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 us to convert the lease into a 20-year leveraged lease
after construction is completed. As of March 31, 2002, the special purpose
entity had drawn down $12.1 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 our leverage ratios and includes, among other restrictions,
financial covenants relating to cash flow leverage, minimum interest coverage
and debt to total book capitalization. We were in compliance with these
covenants as of March 31, 2002. This facility has yet to be syndicated. We are
working with the agent of the facility to modify the facility and are discussing
the conversion of the facility to a term loan in a reduced amount.

The following table summarizes our contractual cash obligations as of March
31, 2002 and the scheduled years in which the obligations are contractually due:

[Enlarge/Download Table]

LESS THAN AFTER
TOTAL 1 YEAR 2-3 YEARS 4-5 YEARS 5 YEARS
-------- --------- --------- --------- --------
(IN THOUSANDS)

Long-term debt....................... $160,324 $ 1,800 $49,809 $ 4,528 $104,187
Q4000 construction and Intrepid
conversion......................... 25,000 25,000 -- -- --
Gunnison development................. 85,000 50,000 35,000 -- --
Operating leases..................... 19,175 2,293 3,058 13,723 101
Redeemable stock in subsidiary....... 7,688 2,563 5,125 -- --
Canyon capital leases and other...... 8,146 2,750 5,396 -- --
-------- ------- ------- ------- --------
Total cash obligations........... $305,333 $84,406 $98,388 $18,251 $104,288
======== ======= ======= ======= ========

In September 2000, in connection with a public offering of common stock by
our former significant shareholder, we sold 610,000 shares of common stock to
cover the underwriters' over-allotment, receiving net proceeds of $14.8 million.

In October 2000, our board of directors declared a two-for-one split of our
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 our financial statements have been restated to reflect the
stock split.

During the first quarter of 2002, we made payments of $826,000 on capital
leases assumed in the Canyon acquisition. The only other financing activity
during the three months ended March 31, 2002 and 2001 and years ended December
31, 2001, 2000 and 1999 involved the exercise of employee stock options.

Capital Commitments. Our capital budget for 2002 includes $50 million for
the completion of the Q4000 and Intrepid, $65 million for the purchase of Canyon
and the addition of three new 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 we 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, we signed a letter of intent to form a 50/50 joint
venture with El Paso Energy Partners, L.P. to construct, install and own a TLP
production hub and associated facilities primarily for Anadarko Petroleum
Corporation's Marco Polo field discovery in the Deepwater Gulf of Mexico.

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Our share of the construction costs is estimated to be $100 million. We, along
with El Paso, are currently negotiating project financing for this venture,
terms of which would include a 30% equity component for us.

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.

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THE INDUSTRY

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
subsea construction 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
Deepwater Gulf; and

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

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

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

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

Deepwater: Water depths beyond 1,000 feet.

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.

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

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

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 federal 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.
28

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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 prospectus 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.

Return on Capital Employed (ROCE): The amount, expressed as a
percentage, earned on a company's total capital (shareholders' equity plus
long-term debt). It is calculated by dividing tax-effected 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 sea bed with
catenary mooring lines.

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

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 feet.

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BUSINESS

We are a leading energy services company specializing in subsea
construction and well operations. We operate in all water depths of the Gulf of
Mexico, with services that cover the lifecycle of an offshore natural gas oil
field. We believe we have a longstanding reputation for innovation in our subsea
construction techniques, equipment design and methods of partnering with
customers. Our diversified fleet of 23 vessels and 19 ROVs performs services
that support drilling, well completion, intervention, 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.

OUR HISTORY

We trace our origins to California Divers Inc., which pioneered the use of
mixed gas diving in the early 1960s when oilfield exploration off the Santa
Barbara coast moved to water depths beyond 250 feet. We commenced operations in
the Gulf of Mexico in 1975. Our growth strategy has frequently involved
expanding beyond our main contracting base and developing innovative service
capabilities to meet customer needs, including the following significant
milestones:

-1984 -- SATURATION VESSELS: Custom designed the first DSV with moonpool
deployed saturation diving systems dedicated for use in the Gulf
of Mexico.

-1986 -- TURNKEY CONTRACTING: Began providing subsea construction work
on a fixed price basis, enabling Gulf customers to better
control project costs.

-1989 -- SALVAGE OPERATIONS: Chartered, and later acquired, the Cal Dive
Barge I for shallow water salvage operations, a business
synergistic with our traditional diving services.

-1992 -- NATURAL GAS PRODUCTION: Formed a natural gas production
company, ERT, to expand customer options for decommissioning of
mature offshore properties and to expand off-season salvage
activity.

-1994 -- DYNAMIC POSITIONING: Chartered a DP DSV for use in the Gulf of
Mexico, enabling it to work through the winter months and in
deeper water. This vessel, the Balmoral Sea, was subsequently
acquired in August 1996.

-1995 -- DP DSV: Acquired and enhanced a DP DSV, the Witch Queen, to
expand our marine construction and subsea services to include
flexible pipelay, umbilical coiled line pipe installation,
decommissioning and ROV support.

-1996 -- MULTI-SERVICE VESSEL: Acquired and enhanced a semi-submersible
MSV, the Uncle John, as the cornerstone of our Deepwater
strategy, thereby expanding our product line to include
geotechnical investigation, laying of infield flowlines,
installation of flexible jumpers, hard jumpers, platforms and
risers, and turnkey field development.

-1997 -- STRATEGIC ASSET ACQUISITIONS AND ALLIANCES: Added two Deepwater
vessels and implemented formal alliance agreements with offshore
service and equipment providers to enhance our ability to
provide the necessary services and assets for full field
development and life of field management.

-1999 -- INCREASED RESERVES AND ADDED NEW CAPABILITIES: Doubled ERT's
proved reserves and annual production; added advanced
capabilities to our Deepwater services with commencement of
construction of the Q4000 and the acquisition of Aquatica, a
shallow water diving company.

-2000 -- PRODUCTION PARTNERING: Expanded our Deepwater strategy by
partnering with one of our customers and acquiring an interest
in Gunnison, a Deepwater Gulf oil and natural gas exploration
project.
30

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-2001 -- STRATEGIC ASSET ACQUISITIONS AND PRODUCTION PARTNERING: Added
two Deepwater vessels and announced a letter of intent to own
50% of the TLP at Marco Polo field.

-2002 -- ACQUIRED CANYON OFFSHORE, INC.: In January 2002, we acquired
Canyon, a supplier of ROVs and robotics to the offshore
construction and telecommunications industries.

OUR VESSELS

We own a fleet of 23 vessels and 19 ROVs. We believe that the Gulf market
requires specially designed and/or equipped vessels to competitively deliver
subsea construction services. Eight of our vessels have DP capabilities
specifically designed to respond to the Deepwater market requirements. Seven 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
Ultra-Deepwater MSV, the Q4000. The vessel has been constructed at an estimated
cost of $182 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 over 4,000 metric tons and upgraded well
completions capability make the vessel particularly well suited for large
offshore construction projects in the Ultra-Deepwater. Its Huisman-Itrec
multi-purpose tower has an open face which allows free access from three sides,
an advantage for a construction and intervention vessel. The Q4000 has recently
completed several projects in the Gulf prior to being deployed to Brazil to
perform work under contract.

Intrepid: We are currently in the final stages of sea trials of the former
Sea Sorceress. She will offer customers a pipelay/construction vessel capable of
carrying an 8,000 metric ton deck load. We expect her to be available for work
the second quarter of 2002.

Mystic Viking: This DP DSV is 240 feet long, 52 feet wide, and is similar
to the Witch Queen with DP-2 redundancy, 500 ton deck load, 2 cranes and a 12
foot x 12 foot moonpool. This vessel was acquired in May 2001.

Eclipse: This large DP DSV is 370 feet long, 67 feet wide and has recently
been reconfigured into a DSV by installing a saturation diving system, restoring
the ballast system and upgrading to DP-2. The Eclipse began work in March 2002.

Northern Canyon: Canyon is scheduled to take delivery of this
purpose-built, 270 foot state-of-the-art ROV support vessel in July 2002. The
vessel, which will be deployed initially in the North Sea, is leased from a
third party.

ROVs: To enable us to control critical path equipment involved in our
deepwater projects, we acquired Canyon in January 2002. Canyon currently owns 19
ROVs and operates eight trenching 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.

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LISTING OF VESSELS, BARGE AND ROVS

[Enlarge/Download Table]

DATE CAL MOONPOOL FOUR
DIVE CLEAR DECK DECK LAUNCH/ POINT CRANE
PLACED IN LENGTH SPACE LOAD ACCOM- SAT ANCHOR CAPACITY
SERVICE (FEET) (SQ. FEET) (TONS) MODATIONS DIVING MOORED (TONS)
--------- ------ ---------- ------ --------- -------- ------ ------------

DP MSVS:
Uncle John............... 11/96 254 11,834 460 102 X -- 2X100
Q4000..................... 4/02 310 26,400 4,000 138 X -- 160; 350;
Derrick: 600
DP ROV SUPPORT VESSELS:
Merlin.................... 12/97 198 955 308 42 -- -- A-Frame
Northern Canyon(2)........ 2002 276 9,677 2,400 60 -- -- 50
DP DSVS:
Witch Queen............... 11/95 278 5,600 500 60 X -- 50
Intrepid (formerly Sea
Sorceress).............. 8/97 374 17,730 8,000 50 -- -- 440
Eclipse................... 3/02 380 8,611 2,436 109 X -- A-Frame
Mystic Viking............. 6/01 253 5,600 1,340 60 X -- 50
DSVS:
Cal Diver I............... 7/84 196 2,400 220 40 X X 20
Cal Diver II.............. 6/85 166 2,816 300 32 X X A-Frame
Cal Diver V............... 9/91 168 2,324 490 30 -- X A-Frame
Talisman.................. 11/00 195 3,000 675 15 -- -- --
AQUATICA DSVS:
Cal Diver III............. 8/87 115 1,320 105 18 -- -- --
Cal Diver IV.............. 3/01 120 1,440 60 24 -- -- --
Mr. Jim................... 2/98 110 1,210 64 19 -- -- --
Mr. Joe................... 10/91 100 1,035 46 16 -- -- --
Mr. Jack.................. 1/98 120 1,220 66 22 -- -- --
Mr. Fred.................. 3/00 167 2,465 500 36 -- X 25
Mr. Sonny(3).............. 3/01 175 3,480 409 28 -- X 35
Polo Pony(3).............. 3/01 110 1,240 69 25 -- -- --
Sterling Pony(3).......... 3/01 110 1,240 64 25 -- -- --
White Pony(3)............. 3/01 116 1,230 64 25 -- -- --
OTHER:
Cal Dive Barge I.......... 8/90 150 N/A 200 26 -- X 200
ROVs (19)................. Various(4) -- -- -- -- -- -- --

CLASSIFICATION(1)
-----------------

DP MSVS:
Uncle John............... DNV
Q4000..................... ABS
DP ROV SUPPORT VESSELS:
Merlin.................... ABS
Northern Canyon(2)........ DNV
DP DSVS:
Witch Queen............... DNV
Intrepid (formerly Sea
Sorceress).............. DNV
Eclipse................... DNV
Mystic Viking............. DNV
DSVS:
Cal Diver I............... ABS
Cal Diver II.............. ABS
Cal Diver V............... ABS
Talisman.................. ABS
AQUATICA DSVS:
Cal Diver III............. ABS
Cal Diver IV.............. ABS
Mr. Jim................... USCG
Mr. Joe................... ABS
Mr. Jack.................. USCG
Mr. Fred.................. USCG
Mr. Sonny(3).............. ABS
Polo Pony(3).............. ABS
Sterling Pony(3).......... ABS
White Pony(3)............. ABS
OTHER:
Cal Dive Barge I.......... ABS
ROVs (19)................. --

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

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

(2) This leased vessel is under construction and should be available in June
2002.

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

(4) Average age of fleet is two years.

We incur routine drydock inspection, maintenance and repair costs pursuant
to Coast Guard regulations and in order to maintain ABS or DNV classification
for our vessels. In addition to complying with these requirements, we have our
own vessel maintenance program which we believe permits us to continue to
provide our customers with well maintained, reliable vessels. In the normal
course of business, we charter other vessels on a short-term basis, such as
tugboats, cargo barges, utility boats and dive support vessels. All of our
vessels are subject to ship mortgages to secure our $60.0 million revolving
credit facility, except the Northern Canyon (which will be leased) and the Q4000
(which is subject to liens to secure the MARAD financing).

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SUBSEA CONTRACTING

We and our alliance partners provide a full range of subsea construction
services, including the following, in both the shallow water 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
semi-submersible DP MSVs, the Q4000 and the Uncle John; two construction DP
DSVs, the Witch Queen and Mystic Viking; two larger mono-hull pipelay and
constructions vessels, the Intrepid and the Eclipse; and two ROV support
vessels, the Merlin and the Northern Canyon. In 2001, vessel enhancements
included the Q4000 (well completion) and the Intrepid (DP-2 capability and a
400-ton crane). The Q4000 was placed into service in April 2002 and the Intrepid
is expected to be available in the second quarter of 2002. When all vessels
begin work, we will have eight world-class DP vessels, seven of which will be
based in the Gulf of Mexico.

With the acquisition of Canyon we have increased our ROV and trenching
fleet to 27. Canyon's 19 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. We currently own 19 ROV systems and
operate eight others in three regions: the Americas (14), Southeast Asia (8),
and the North Sea (5). Our ROV assets will help to provide our customers with
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 with 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; and 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 of such work has been
completed from drilling rigs.

We are a leader in solving the operational challenges encountered in
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 service while
maintaining our low overhead base. These alliances are:

-- 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

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While the DP construction market remained soft, our significant increase in
utilization to 87% in 2001 from 56% in 2000, reflects improvement in our market
share and an expansion in the scope of Deepwater Gulf installations. Major
projects in 2001 and 2002 were:

[Download Table]

DEPTH
FIELD CUSTOMER DESCRIPTION (FEET)
----- -------- ----------- ------

Diana Exxon Riser tie-in, spool and strake
installations 4,600
Marshall/Madison Exxon Jumper and flying lead installations 6,000
Mica Exxon Manifold, suction pile and tree
installations 4,500
Nansen/Boomvang Kerr-McGee Plet, flexible riser, umbilicals flying
lead and jumper installations 3,700

SHELF CONTRACTING

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

We deliver our services in the shallow water market, from the beach to 300
feet, through our wholly-owned subsidiary, Aquatica. In March 2001, Aquatica
acquired substantially all of the business of Professional Divers, effectively
doubling the size of our DSV fleet. We also perform numerous projects on the OCS
in an alliance with Horizon. In the late 1980s 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. Under the alliance, we have the
exclusive right to provide DSV services behind Horizon pipelay barges while
Horizon supplies pipelay, derrick barge and heavy lift capacity to us. The
recent expansion of the alliance also resulted in our providing the diving
personnel working from Horizon barges, a service Horizon previously handled
internally. 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.

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

PRODUCTION PARTNERING

We formed ERT in 1992 to exploit a market opportunity to provide a more
efficient solution to offshore abandonment, to expand our off-season salvage and
decommissioning activity and to support full field production development
projects. Through Production Partnering, we offer customers the option of
selling unsuccessful field developments or mature offshore fields rather than
contracting and managing the many phases of the decommissioning process. The
advantages of our production business are fourfold. First, oil and gas revenues
counteract the volatility in revenues and income we experience in offshore
construction. Second, in periods of excess capacity such as in 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 partially 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, a major objective of our
investments in oil and gas properties is to secure the associated marine
construction work.

There are over 110 announced commercial discoveries in the Deepwater Gulf
that have yet to be brought into production. Many of these are smaller
reservoirs that standing alone cannot justify the economics of a host production
facility. As a result we expect that the Deepwater Gulf will be developed in a
hub and satellite field

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concept that resembles the approach the airline industry has used with regional
hub locations. We expect 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 have not been signed, our 50%
ownership in the production facility would allow us to realize a transmission
return consisting of both a fixed demand and tariff charge. In addition we hope
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 our construction
vessels.

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 generates income in three ways:
lowering salvage costs by using our assets, operating the field more cost
effectively and extending reservoir life through well exploitation operations.
The periodic collapses of commodity prices in the last few years removed some of
the small companies which previously bought mature properties. Our customers
must assume responsibility when buyers are no longer available to perform
abandonment obligations. A significant development in the past two years has
been the entry of two competitors which have captured significant market share.
In the face of this competition, we completed only three small mature property
acquisitions in 2001, as high commodity prices made such purchases difficult.
Rather than pursue mature properties at high prices during the upcycle, our
recent emphasis has been to extract more value from the existing property base.
During 2001, 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 Mcfe.

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, prepared in accordance with guidelines
established by the Securities and Exchange Commission. The reserves assigned to
Gunnison, which constitute over 75% of our reported proved reserves as of
December 31, 2001, were computed as 15% of the reserves reported by the
operator. The remainder of our reserves are based on estimates reviewed by
Miller and Lents, Ltd.

[Download Table]

TOTAL PROVED
------------

Estimated Proved Reserves:
Natural gas (Mmcf)........................................ 53,936
Oil and condensate (MBbls)................................ 7,858
Standardized measure of discounted future net cash flows
(pre-tax)(1).............................................. $39,257,000
-----------

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

(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, we owned 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.

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 Corp. (10%); 2000 -- Enron Corp.
(13%); and 1999 -- EEX Corporation (13%). We estimate that in 2001 we provided
subsea services to over 200 customers. Horizon was our largest customer in 2001,
representing 18% of our consolidated revenue. Our projects are typically of
short duration and are generally awarded shortly before mobilization.
Accordingly, we believe backlog is not a meaningful indicator of future business
results.

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COMPETITION

The subsea services industry is highly competitive. While price is a
factor, the ability to acquire 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
potential purchasers of natural gas and oil properties are well-established
companies with substantially larger operating staffs and greater capital
resources.

TRAINING, SAFETY AND QUALITY ASSURANCE

We have established a corporate culture in which safety is expected to be
the number one priority. Our corporate goal, based on the belief that all
accidents are preventable, is to provide an injury-free workplace by focusing on
correct safety behavior. Our safety procedures and training programs were
developed by management personnel who came into the industry as divers and who
know first hand the physical challenges of the ocean work site. As a result,
management believes that our safety programs are among the best in the industry.
We have introduced a company-wide effort to enhance a behavioral safety process
and training program that makes safety a constant focus of awareness through
open communication with all offshore and yard employees. The process includes
the documentation of all daily observations and the collection of this data. In
addition, we initiated regular monthly visits by project managers to conduct
"Hazard Hunts" on each vessel, providing a "safety audit" with a fresh
perspective. First year results from this program were evident as our safety
performance improved dramatically in 2001.

FACILITIES

Our corporate headquarters are located at 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.

PROPERTIES AND FACILITIES SUMMARY

[Enlarge/Download Table]

FUNCTION SIZE
-------- ----

Houston, Texas.................. Cal Dive corporate headquarters, 37,800 square feet
project management and sales
office
Canyon corporate headquarters 15,000 square feet
management and sales office
Aberdeen, Scotland.............. Canyon sales office 12,000 square feet
Singapore....................... Canyon operations 10,000 square feet
Morgan City, Louisiana.......... Cal Dive operations 28.5 acres
Warehouse 30,000 square feet
Offices 4,500 square feet
Lafayette, Louisiana............ Aquatica operations 8 acres
Warehouse 12,000 square feet
Offices 5,500 square feet

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

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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, the Minerals Management
Service, or 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
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, or OCSLA. These MMS directives are subject to change. The MMS has
promulgated regulations requiring offshore production facilities located on the
OCS to meet stringent engineering and construction specifications. The MMS also
has issued regulations restricting the flaring or venting of natural gas and
prohibiting the burning of liquid hydrocarbons without prior authorization.
Similarly, the MMS has promulgated other regulations governing the plugging and
abandonment of wells located offshore and the removal of all production
facilities. Finally, under certain circumstances, the MMS may require any
operations on federal leases to be suspended or terminated. 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 and the Federal Oil and Gas Royalty Management Act, MMS
also administers oil and gas leases and establishes regulations that set the
basis for royalties on oil and gas produced from the leases. The MMS amends
these regulations from time to time. For example, on March 15, 2000, the MMS
issued a final rule governing the calculation of royalties and the valuation of
crude oil produced from federal leases. The 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 royalties
owed, the rule disallows as deductions certain costs, such as
aggregator/marketer fees and transportation imbalance charges and associated
penalties. A United States District Court enjoined substantial portions of this
rule on March 28, 2000. The United States appealed the district court decision.
On February 8, 2002, the Court of Appeals for the District of Columbia reversed
the District Court and reinstated the regulations. The appellees sought
reconsideration and those petitions are pending.

Historically, the transportation and sale for resale of natural gas in
interstate commerce has been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978, or NGPA, and the

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regulations promulgated thereunder by the Federal Energy Regulatory Commission,
or 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 us differently than
other companies with which we compete.

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

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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 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 results of operations. As of this date, we believe we
are not the subject of any civil or criminal enforcement actions under OCSLA.

The Comprehensive Environmental Response, Compensation, and Liability Act,
or CERCLA, contains provisions requiring the remediation of releases of
hazardous substances into the environment and imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
including owners and operators of contaminated sites where the release occurred
and those companies who transport, dispose of or who arrange for disposal of
hazardous substances released at the sites. Under CERCLA, such persons may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages
to natural resources and for the costs of certain health
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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.

INSURANCE AND LITIGATION

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

We are involved in various legal proceedings, primarily involving claims
for personal injury under the General Maritime Laws of the United States and the
Jones Act as a result of alleged negligence. In addition, we from time to time
incur other claims, such as contract disputes, in the normal course of business.
In that regard, in 1998, one of our subsidiaries entered into a subcontract with
Seacore Marine Contractors Limited to provide the Sea Sorceress to a Coflexip
subsidiary in Canada. Due to difficulties with respect to the sea states and
soil conditions the contract was terminated and an arbitration to recover
damages was commenced. A preliminary liability finding has been made by the
arbitrator against Seacore and in favor of the Coflexip subsidiary. We were not
a party to this arbitration proceeding. Only one of the grounds is potentially
applicable to our subsidiary. In the event that Seacore chooses to seek
contribution from our subsidiary, which could entail another arbitration, it is
anticipated that our subsidiary's exposure, if any, should be less than
$500,000. In another lengthy 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.
We have responded alleging EEX Corporation breached various provisions of the
same contracts and are defending the litigation vigorously. Although such
litigation has the potential for significant liability, we believe that the
outcome of all such proceedings is not likely to have a material adverse effect
on our consolidated financial position, results of operations or net cash flows.

EMPLOYEES

We rely on the high quality of our workforce. As of March 31, 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. We believe that our
relationship with our employees and foreign crew members is good.

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MANAGEMENT

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

[Enlarge/Download Table]

NAME AGE POSITION
---- --- --------

Owen Kratz(3)(4)..................... 47 Chairman and Chief Executive Officer and
Director
Martin R. Ferron..................... 45 President and Chief Operating Officer and
Director
S. James Nelson, Jr. ................ 60 Vice Chairman and Director
James Lewis Connor, III.............. 44 Senior Vice President and General Counsel
A. Wade Pursell...................... 37 Senior Vice President and Chief Financial
Officer
Michael V. Ambrose................... 55 Senior Vice President -- Deepwater Contracting
Gordon F. Ahalt(1)(2)(4)............. 73 Director
Bernard J. Duroc-Danner(1)(2)(3)..... 48 Director
William L. Transier(1)(2)(3)(4)...... 47 Director

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

(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 I directors, Owen Kratz and Bernard Duroc-Danner, expire in 2004. The
terms of the Class II directors, Gordon Ahalt and Martin R. Ferron, expire in
2002. The terms of the Class III directors, S. James Nelson, Jr. and William L.
Transier, expire in 2003. 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 our
Chief Executive Officer since April 1997. Mr. Kratz served as President from
1993 until February 1999, and as a Director since 1990. He served as Chief
Operating Officer from 1990 through 1997. Mr. Kratz joined Cal Dive in 1984 and
has held various offshore positions, including saturation diving supervisor, and
has had management responsibility for client relations, marketing and
estimating. From 1982 to 1983, Mr. Kratz was the owner of an independent marine
construction company operating in the Bay of Campeche. Prior to 1982, he was a
superintendent for Santa Fe and various international diving companies, and a
saturation diver in the North Sea.

Martin R. Ferron has served on our board of directors since September 1998.
Mr. Ferron became President in February 1999 and has served as Chief Operating
Officer since January 1998. Mr. Ferron has 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.

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

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

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

Michael V. Ambrose became Senior Vice President -- Deepwater Contracting in
July 2001. He joined Cal Dive in August 1997 as a project manager and became
Vice President-Major Projects in May 1998. 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. From 1982 to 2001, Mr.
Ahalt was 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 private 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; a manufacturer and supplier of
oilfield drill pipe and related products, 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., a oil and gas exploration and production company, 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 an
MBA from Regis University. He is a director of Metals USA, an integrated metals
processing and distribution company.

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DESCRIPTION OF CAPITAL STOCK

Our amended and restated articles of incorporation provide for authorized
capital stock of 120,000,000 shares of common stock, of which 33,285,927 shares
were issued and outstanding on May 2, 2002, and 5,000,000 shares of preferred
stock, of which no shares are issued and outstanding. The following summary
description of our capital stock is qualified in its entirety by reference to
the articles of incorporation and our amended and restated bylaws, each of which
is incorporated by reference.

COMMON STOCK

The holders of common stock are entitled to one vote for each share on all
matters voted on by shareholders, and except as otherwise required by law or as
provided in any resolution adopted by the board of directors with respect to any
series of preferred stock, the holders of shares of common stock exclusively
possess all voting power.

Subject to any preferential rights of any outstanding series of preferred
stock created by the board of directors from time to time, the holders of common
stock are entitled to such dividends as may be declared from time to time by the
board of directors from funds available therefore, and upon liquidation will be
entitled to receive pro rata all assets of Cal Dive available for distribution
to such holders. The common stock is not convertible or redeemable and there are
no sinking fund provisions therefore. Holders of the common stock are not
entitled to any preemptive rights.

PREFERRED STOCK

Our board of directors, without any action by our shareholders, is
authorized to issue up to 5,000,000 shares of preferred stock, in one or more
series and to determine the voting rights, preferences as to dividends and
assets in liquidation and the conversion and other rights of each such series.
There are no shares of preferred stock outstanding. See "Certain Anti-takeover
Provisions" below with regard to the effect that the issuance of preferred stock
might have on attempts to take over Cal Dive.

CERTAIN ANTI-TAKEOVER PROVISIONS

The articles of incorporation and bylaws contain a number of provisions
that could make the acquisition of Cal Dive by means of a tender or exchange
offer, a proxy contest or otherwise more difficult. The description of those
provisions set forth below is intended to be only a summary and is qualified in
its entirety by reference to the pertinent sections of the articles of
incorporation and the bylaws, which are incorporated by reference into this
prospectus.

Classified Board of Directors; Removal of Directors. Our directors are
currently divided into three classes, only one class of which is subject to
re-election in any given year. The classification of directors will have the
effect of making it more difficult for shareholders to change the composition of
the board of directors. At least two annual meetings of shareholders generally
will be required to effect a change in majority of the board of directors. Such
a delay may help ensure that our directors, if confronted by a shareholder
attempting to force a proxy contest, a tender or exchange offer or an
extraordinary corporate transaction, would have sufficient time to review the
proposal as well as any available alternatives to the proposal and to act in
what they believe to be the best interest of the shareholders. The
classification provisions will apply to every election of directors, however,
regardless of whether a change in the composition of the board of directors
would be beneficial to us and our shareholders and whether a majority of our
shareholders believes that such a change would be desirable.

The articles of incorporation provide that our directors may only be
removed by the affirmative vote of the holders of 68% of the voting power of all
the then outstanding shares of stock entitled to vote generally in the election
of directors (the "Voting Stock").

The classification provisions could also have the effect of discouraging a
third party from initiating a proxy contest, making a tender or exchange offer
or otherwise attempting to obtain control of Cal Dive, even though such an
attempt might be beneficial to us and our shareholders. These provisions could
thus increase the
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likelihood that incumbent directors will retain their positions. In addition,
the classification provisions may discourage accumulations of large blocks of
our common stock that are effected for purposes of changing the composition of
the board of directors. Accordingly, shareholders could be deprived of certain
opportunities to sell their shares of common stock at a higher market price than
might otherwise be the case.

Preferred Stock. The articles of incorporation authorize the board of
directors to establish one or more series of preferred stock and to determine,
with respect to any series of preferred stock, the terms and rights of such
series, including:

-- the designation of the series;

-- the number of shares of the series, which number the board may
thereafter (except where otherwise provided in the certificate of
designation) increase or decrease (but not below the number of shares
thereof then outstanding);

-- whether dividends, if any, will be cumulative or noncumulative and
the dividend rate of the series;

-- the dates at which dividends, if any, will be payable;

-- the redemption rights and price or prices, if any, for shares of the
series;

-- the terms and amounts of any sinking fund provided for the purchase
or redemption of shares of the series;

-- the amounts payable on shares of the series in the event of any
voluntary or involuntary liquidation, dissolution or winding up of
the affairs of Cal Dive;

-- whether the shares of the series will be convertible into shares of
any other class or series, or any other security, of Cal Dive or any
other corporation, and, if so, the specification of the other class
or series or the other security, the conversion price or prices or
rate or rates, any adjustments thereof, the date or dates as of which
such shares shall be convertible and all of the terms and conditions
upon which such conversion may be made;

-- restrictions, if any, on the issuance of shares of the same series or
of any other class or series; and

-- voting rights, if any, of the shareholder of such series, which may
include the right of such shareholders to vote separately as a class
on any matter.

We believe that the ability of the board of directors to issue one or more
series of preferred stock will provide us with flexibility in structuring
possible future financings and acquisitions and in meeting other corporate needs
which might arise. The authorized shares or preferred stock, as well as shares
of common stock, will be available for issuance without further action by our
shareholders, unless that action is required by applicable law or the rules of
any stock exchange or automated quotation system on which our securities may be
listed or traded.

Although the board of directors has no intention at the present time of
doing so, it could issue a series of preferred stock that, depending on the
terms of such series, might impede the completion of a proxy contest, merger,
tender or exchange offer or other attempt to obtain control of Cal Dive. The
board of directors will make any determination to issue such shares based on its
judgment as to the best interests of Cal Dive and our shareholders. The board of
directors, in so acting, could issue preferred stock having terms that could
discourage an acquisition attempt through which an acquiror may be otherwise
able to change the composition of the board of directors, including a tender or
exchange offer or other transaction that some, or a majority of our shareholders
might believe to be in their best interests or in which shareholders might
receive a premium for their stock over the then current market price of such
stock.

No Shareholder Action by Written Consent; Special Meetings. The articles
of incorporation and bylaws provide that shareholder action can be taken only at
an annual or special meeting of shareholders and prohibit shareholder action by
written consent in lieu of a meeting. The bylaws provide that special meetings
of shareholders can be called only upon a written request by the chief executive
officer or a majority of the

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members of the board of directors. Shareholders are not permitted to call a
special meeting or to require that the board of directors call a special
meeting.

The provisions of the articles of incorporation and the bylaws prohibiting
shareholder action by written consent may have the effect of delaying
consideration of a shareholder proposal, including a shareholder proposal that a
majority of shareholders believes to be in the best interest of Cal Dive, until
the next annual meeting unless a special meeting is called. These provisions
would also prevent the holders of a majority of the Voting Stock from
unilaterally using written consents to take shareholder action. Moreover, a
shareholder could not force shareholder consideration of a proposal over the
opposition of the board of directors by calling a special meeting of
shareholders prior to the time a majority of the board of directors believes
such consideration to be appropriate.

Amendment of Certain Provisions of the Articles of Incorporation and
Bylaws. Under the Minnesota Business Corporation Act (the "MBCA"), the
shareholders have the right to adopt, amend or repeal the bylaws and, with the
approval of the board of directors, the articles of incorporation. The articles
of incorporation provide that the affirmative vote of the holders of at least
80% of the voting power of the then outstanding shares of Voting Stock, voting
together as a single class, and in addition to any other vote required by the
articles of incorporation or bylaws, is required to amend provisions of the
articles of incorporation of bylaws relating to:

-- the prohibition of shareholder action without a meeting;

-- the prohibition of shareholders calling a special meeting;

-- the number, election and term of our directors;

-- the removal of directors; and

-- fixing a quorum for meetings of shareholders.

The vote of the holders of a majority of the voting power of the
outstanding shares of Voting Stock is required to amend all other provisions of
the articles of incorporation. The bylaws further provide that the bylaws may be
amended by the board of directors. These super-majority voting requirements will
have the effect of making more difficult any amendment by shareholders of the
bylaws or of any of the provisions that such amendment would be in their best
interests.

Anti-takeover Legislation. As a public corporation, we are governed by the
provisions of Section 302A.673 of the MBCA. This anti-takeover provision may
eventually operate to deny shareholders the receipt of a premium on their common
stock and may also have a depressive effect on the market price of our common
stock. Section 302A.673 prohibits a public corporation from engaging in a
"business combination" with an "interested shareholder" for a period of four
years after the date of the transaction in which the person became an interested
shareholder, unless the business combination is approved by a committee of all
of the disinterested members of our board of directors before the interested
shareholder's share acquisition date. A "business combination" includes mergers,
asset sales and other transaction. An "interested shareholder" is a person who
is the beneficial owner of 10% or more of the corporation's Voting Stock.
Reference is made to the detailed terms of Section 302A.673 of the MBCA.

LIMITATION ON DIRECTORS' LIABILITY AND INDEMNIFICATION OF DIRECTORS AND OFFICERS

The articles of incorporation contain a provision that eliminates, to the
extent currently allowed under the MBCA, the personal monetary liability of a
director to Cal Dive and our shareholders for breach of fiduciary duty of care
as a director, except in certain circumstances. If a director of Cal Dive were
to breach such fiduciary duty of care in performing duties as a director,
neither Cal Dive nor our shareholders could recover monetary damages from the
director, and the only course of action available to our shareholders would be
equitable remedies, such as an action to enjoin or rescind a transaction
involving a breach of the fiduciary duty of care. To the extent certain claims
against directors are limited to equitable remedies, this provision of the
articles of incorporation may reduce the likelihood of derivative litigation
against directors for breach of their fiduciary duty of care. Additionally,
equitable remedies may not be effective in many situations. If a
45

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shareholder's only remedy is to enjoin the completion of the board of directors'
action, this remedy would be ineffective if the shareholder does not become
aware of a transaction or event until after its has been completed. In such a
situation, such shareholder would not have effective remedy against the
directors.

Our bylaws require us to indemnify directors and officers to the fullest
extent permitted under Minnesota law. The MBCA provides that a corporation
organized under the Minnesota law shall indemnify any director, officer,
employee or agent of the corporation made or threatened to be made a party to a
proceeding, by reason of the former or present official capacity (as defined in
the MBCA) of the person, against judgments, penalties, fines, settlements, and
reasonable expense incurred by the person in connection with the proceedings if
certain statutory standards are met. "Proceeding" means a threatened, pending or
completed civil, criminal, administrative, arbitration or investigative
proceeding, including one by or in the right of the corporation. Selection
302A.521 of the MBCA contains detailed terms regarding such rights of
indemnification and reference is made thereto for a complete statement of such
indemnification rights.

All of the foregoing indemnification provisions include statements that
such provisions are not to be deemed exclusive of any other right to indemnity
to which a director or officer may be entitled under any bylaw, agreement, vote
of shareholders or disinterested directors or otherwise.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common stock is Wells Fargo Bank
Northwest, National Association.

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UNDERWRITERS

Under the terms and subject to the conditions contained in an underwriting
agreement, the underwriters named below, for whom Morgan Stanley & Co.
Incorporated, Salomon Smith Barney Inc., Raymond James & Associates, Inc. and
Simmons & Company International are acting as representatives, have severally
agreed to purchase, and we have agreed to sell to them, severally, the number of
shares of our common stock indicated below:

[Download Table]

NUMBER OF
NAME SHARES
---- ---------

Morgan Stanley & Co. Incorporated........................... 988,368
Salomon Smith Barney Inc. .................................. 988,368
Raymond James & Associates, Inc. ........................... 823,640
Simmons & Company International............................. 494,184
Frost Securities, Inc. ..................................... 50,000
Ryan, Beck & Co., Inc. ..................................... 50,000
UBS Warburg LLC............................................. 50,000
---------
Total....................................................... 3,444,560
=========

The underwriters are offering the shares subject to their acceptance of the
shares from us and subject to prior sale. The underwriting agreement provides
that the obligations of the several underwriters to pay for and accept delivery
of the shares of common stock offered by this prospectus are subject to the
approval of certain legal matters by their counsel and to certain other
conditions. The underwriters are obligated to take and pay for all of the shares
of common stock offered in this offering, other than those covered by the
over-allotment option described below, if any of the shares are taken. However,
the underwriters are not required to take or pay for the shares covered by the
underwriters' over-allotment option described below.

The underwriters initially propose to offer part of the shares of common
stock directly to the public at the public offering price set forth on the cover
page of this prospectus and part to certain dealers at a price that represents a
concession not in excess of $0.67 a share under the public offering price. After
the initial offering of the shares of common stock, the offering price and other
selling terms may from time to time be varied by the representatives of the
underwriters.

We have granted to the underwriters an option, exercisable for 30 days from
the date of this prospectus, to purchase up to an aggregate of 516,684
additional shares of our common stock at the public offering price listed on the
cover page of this prospectus, less underwriting discounts and commission. The
underwriters may exercise this option solely for the purpose of covering
over-allotments, if any, made in connection with the offering of the shares of
our common stock offered by this prospectus. To the extent the option is
exercised, each underwriter will become obligated, subject to specified
conditions, to purchase about the same percentage of the additional shares as
the number listed next to the underwriters' option is exercised in full, the
total price to the public would be $91.7 million, the total underwriters'
discounts and commissions would be $4.1 million and our total net proceeds would
be $87.6 million.

We will pay substantially all of the expenses of the offering, which we
estimate will be approximately $310,000.

We and our directors and executive officers have agreed that, without the
prior written consent of Morgan Stanley & Co. Incorporated on behalf of the
underwriters, during the period ending 90 days after the date of this
prospectus, each of them will not, directly or indirectly:

-- offer, pledge, sell, contract to sell, sell any option or contract to
purchase, purchase any option or contract to sell, grant any option,
right or warrant to purchase, lend or otherwise transfer or dispose
of, directly or indirectly, any shares of common stock or any
securities convertible into or exercisable or exchangeable for common
stock; or

424B4 48th Page of 76 TOC 1st Previous Next ↓Bottom Just 48th
-- enter into any swap or other arrangement that transfers to another,
in whole or in part, any of the economic consequences of ownership of
common stock,

whether any such transaction described above is to be settled by delivery of
common stock or such other securities, in cash or otherwise.

The restrictions described in the previous paragraph do not apply to:

-- the sale of shares of common stock to the underwriters under the
underwriting agreement;

-- transactions by any person other than us relating to shares of common
stock or other securities acquired in open market transactions after
the completion of this offering;

-- certain transfers to trusts or family limited partnerships, provided
that a transferee agrees to be subject to the restrictions described
above;

-- sales after 30 days after the date of this prospectus of up to an
aggregate of 30,000 shares of our common stock by certain of our
executive officers; and

-- issuances of shares of common stock or options to purchase shares of
common stock pursuant to our employee benefit plans as in existence
on the date of this prospectus and consistent with past practices.

In order to facilitate the offering of the common stock, the underwriters
may engage in transactions that stabilize, maintain or otherwise affect the
price of the common stock. Specifically, the underwriters may over-allot in
connection with the offering, creating a short position in the common stock for
their own account. In addition, to cover over-allotments or to stabilize the
price of the common stock, the underwriters may bid for, and purchase, shares of
common stock in the open market. Finally, the underwriting syndicate may reclaim
selling concessions allowed to an underwriter or a dealer for distributing the
common stock in the offering if the syndicate repurchases previously distributed
shares of common stock in transactions to cover syndicate short positions, in
stabilization transactions or otherwise. Any of these activities may stabilize
or maintain the market price of the common stock above independent market
levels. The underwriters are not required to engage in these activities and may
end any of these activities at any time.

From time to time, some of the underwriters have provided, and may continue
to provide, investment banking services to us.

We have agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act of 1933.

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LEGAL MATTERS

The validity of the common stock offered under this prospectus will be
passed upon by our Corporate Secretary, Andrew C. Becher, certain other legal
matters will be passed upon for Cal Dive by our Senior Vice President and
General Counsel, James Lewis Connor, III, and certain other legal matters will
be passed upon for Cal Dive by Fulbright & Jaworski L.L.P., Houston, Texas. As
of May 3, 2002 lawyers at Fulbright & Jaworski L.L.P. working on this offering
owned 2,000 shares of our common stock. Baker Botts L.L.P., Houston, Texas will
pass on certain legal matters for the underwriters. James Lewis Connor, III,
Fulbright & Jaworski L.L.P. and Baker Botts L.L.P. will not pass on any matters
of Minnesota law.

EXPERTS

The consolidated balance sheets as of December 31, 2000 and 2001 and the
related consolidated statements of operations, cash flows and shareholders'
equity for the three years in the period ended December 31, 2001 included in
this prospectus and incorporated by reference elsewhere in the registration
statement have been audited by Arthur Andersen LLP, independent public
accountants, as indicated in their report with respect thereto, and are included
herein in reliance upon the authority of said firm as experts in accounting and
auditing in giving said report.

The estimated reserve evaluations (excluding Gunnison) and related
calculations of Miller & Lents, Ltd. included or incorporated by reference in
this prospectus and elsewhere in this registration statement have been included
herein reliance upon the authority of said firm as an expert in petroleum
engineering.

OTHER MATTERS

On March 14, 2002, our independent public accountant, Arthur Andersen LLP,
was indicted on federal obstruction of justice charges arising from the federal
government's investigation of Enron Corp. Arthur Andersen LLP has pled not
guilty and indicated that it intends to contest the indictment. Given the
uncertainty surrounding the indictment, it may become difficult for you to seek
remedies against Arthur Andersen LLP. Our Audit Committee has been monitoring
these developments carefully, and has authorized management to obtain proposals
from other "big five" accounting firms for our 2002 audit. We have not yet
determined whether to engage independent public accountants other than Arthur
Andersen LLP for our 2002 audit. As a public company, we are required to file
with the Securities and Exchange Commission periodic financial statements
audited or reviewed by an independent public accountant. The Securities and
Exchange Commission has said that it will continue accepting financial
statements audited by Arthur Andersen LLP, and interim financial statements
reviewed by it, so long as Arthur Andersen LLP is able to make certain
representations to its clients concerning audit quality controls. Arthur
Andersen LLP has made the required representations to us.

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WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and special reports, proxy statements and other
information with the Securities and Exchange Commission (SEC). Our SEC filings
are available to the public over the Internet at the SEC's web site at
http://www.sec.gov. You may also read and copy any document we file at the SEC's
public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549, and at
500 West Madison Street, Suite 1400, Chicago, Illinois 60661. You may obtain
information on the operation of the SEC's public reference room in Washington,
D.C. by calling the SEC at 1-800-SEC-0330.

Our common stock is listed on the Nasdaq National Market System under the
symbol "CDIS." Our reports, proxy statements and other information may be read
and copied at the National Association of Securities Dealers, Inc. at 1735 K
Street, N.W., Washington, D.C. 20006.

This prospectus constitutes part of a registration statement on Form S-3
filed with the SEC under the Securities Act of 1933. It omits some of the
information contained in the registration statement, and reference is made to
the registration statement for further information with respect to us and the
securities we are offering. Any statement contained in this prospectus
concerning the provisions of any document filed as an exhibit to the
registration statement or otherwise filed with the SEC is not necessarily
complete, and in each instance reference is made to the copy of the document
filed.

INFORMATION INCORPORATED BY REFERENCE

The SEC allows us to "incorporate by reference" information into this
prospectus, which means that we can disclose important information to you by
referring you to another document filed separately with the SEC. The information
incorporated by reference is deemed to be part of this prospectus, except for
any information superseded by information in this prospectus. This prospectus
incorporates by reference the documents set forth below that we previously filed
with the SEC. These documents contain important information about us.

The following documents that we have filed with the SEC (File No. 0-22739)
are incorporated by reference into this prospectus:

-- Our Annual Report on Form 10-K for the year ended December 31, 2001;
and

-- Our Quarterly Report on Form 10-Q for the quarter ended March 31,
2002.

All documents that we file pursuant to Sections 13(a), 13(c), 14 or 15(d)
of the Securities Exchange Act of 1934 after the date of this prospectus will be
deemed to be incorporated in this prospectus by reference and will be a part of
this prospectus from the date of the filing of the document. Any statement
contained in a document incorporated or deed to be incorporated by reference in
this prospectus will be deemed to be modified or superseded for purposes of this
prospectus to the extent that a statement contained in this prospectus or in any
other subsequently filed document which also is or is deemed to be incorporated
by reference in this prospectus modifies or supersedes that statement. Any
statement that is modified or superseded will not constitute a part of this
prospectus, except as modified or superceded.

We will provide without charge to each person, including any beneficial
owner, to whom a copy of this prospectus has been delivered, upon written or
oral request, a copy of any or all of the documents incorporated by reference in
this prospectus, other than the exhibits to those documents, unless the exhibits
are specifically incorporated by reference into the information that this
prospectus incorporates. You should direct a request for copies to us at 400 N.
Sam Houston Parkway E., Suite 400, Houston, Texas, 77060, Attention: Corporate
Secretary (telephone number: (281) 618-0400).

424B4 51st Page of 76 TOC 1st Previous Next ↓Bottom Just 51st
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

[Download Table]

PAGE
----

Report of Independent Public Accountants.................... F-2
Consolidated Balance Sheets--March 31, 2002, December 31,
2001 and 2000............................................. F-3
Consolidated Statements of Operations for the three months
ended March 31, 2002 and 2001 and years ended December 31,
2001, 2000 and 1999....................................... F-4
Consolidated Statements of Shareholders' Equity for the
three months ended March 31, 2002 and years ended December
31, 2001, 2000 and 1999................................... F-5
Consolidated Statements of Cash Flows for the three months
ended March 31, 2002 and 2001 and years ended December 31,
2001, 2000 and 1999....................................... F-6
Notes to Consolidated Financial Statements.................. F-7

F-1

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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

F-2

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CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

[Enlarge/Download Table]

DECEMBER 31,
MARCH 31, -------------------
2002 2001 2000
----------- -------- --------
(UNAUDITED)

ASSETS
Current assets:
Cash and cash equivalents............................... $ 4,103 $ 37,123 $ 44,838
Restricted cash......................................... -- -- 2,624
Accounts receivable--
Trade, net of revenue allowance on gross amounts
billed of $5,661, $4,262 and $1,770................ 56,872 45,527 42,924
Unbilled revenue..................................... 11,653 10,659 1,902
Income tax receivable................................... -- -- 10,014
Other current assets.................................... 21,240 20,055 20,975
-------- -------- --------
Total current assets............................ 93,868 113,364 123,277
-------- -------- --------
Property and equipment.................................... 480,863 423,742 266,102
Less--Accumulated depreciation.......................... (94,221) (92,430) (67,560)
-------- -------- --------
386,642 331,312 198,542
Other assets:
Goodwill, net........................................... 60,185 14,973 12,878
Other assets, net....................................... 14,767 13,473 12,791
-------- -------- --------
$555,462 $473,122 $347,488
======== ======== ========

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable........................................ $ 31,625 $ 42,252 $ 25,461
Accrued liabilities..................................... 19,822 21,011 21,435
Income taxes payable.................................... -- -- --
Current maturities of long-term debt.................... 4,550 1,500 --
-------- -------- --------
Total current liabilities....................... 55,997 64,763 46,896
-------- -------- --------
Long-term debt............................................ 163,920 98,048 40,054
Deferred income taxes..................................... 58,178 54,631 38,272
Decommissioning liabilities............................... 32,528 29,331 27,541
Redeemable stock in subsidiary............................ 7,688 -- --
Commitments and contingencies
Shareholders' equity:
Common stock, no par, 120,000 shares authorized, 46,837,
46,239 and 45,885 shares issued...................... 104,332 99,105 93,838
Retained earnings....................................... 136,571 133,570 104,638
Treasury stock, 13,602, 13,783 and 13,640 shares, at
cost................................................. (3,752) (6,326) (3,751)
-------- -------- --------
Total shareholders' equity...................... 237,151 226,349 194,725
-------- -------- --------
$555,462 $473,122 $347,488
======== ======== ========

The accompanying notes are an integral part of these consolidated financial
statements.
F-3

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CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

[Enlarge/Download Table]

THREE MONTHS
ENDED MARCH 31, YEAR ENDED DECEMBER 31,
----------------- ------------------------------
2002 2001 2001 2000 1999
------- ------- -------- -------- --------
(UNAUDITED)

Net revenues:
Subsea and salvage...................... $44,370 $31,282 $163,740 $110,217 $128,435
Natural gas and oil production.......... 9,558 27,200 63,401 70,797 32,519
------- ------- -------- -------- --------
53,928 58,482 227,141 181,014 160,954
Cost of sales:
Subsea and salvage...................... 37,690 25,170 127,047 94,104 103,113
Natural gas and oil production.......... 5,120 11,054 33,183 31,541 20,590
------- ------- -------- -------- --------
Gross profit......................... 11,118 22,258 66,911 55,369 37,251
Selling and administrative expenses....... 6,306 5,607 21,325 20,800 13,227
------- ------- -------- -------- --------
Income from operations.................. 4,812 16,651 45,586 34,569 24,024
Equity in earnings of Aquatica, Inc..... -- -- -- -- 600
Net interest (income) expense and
other................................ 196 291 1,290 554 (849)
------- ------- -------- -------- --------
Income before income taxes................ 4,616 16,360 44,296 34,015 25,473
Provision for income taxes.............. 1,615 5,726 15,504 11,555 8,465
Minority Interest....................... -- (140) (140) (866) 109
------- ------- -------- -------- --------
Net income...................... $ 3,001 $10,774 $ 28,932 $ 23,326 $ 16,899
======= ======= ======== ======== ========
Net income per share:
Basic................................... $ 0.09 $ 0.33 $ 0.89 $ 0.74 $ 0.56
Diluted................................. 0.09 0.33 0.88 0.72 0.55
======= ======= ======== ======== ========
Weighted average common shares
outstanding:
Basic................................... 32,648 32,308 32,449 31,588 30,016
Diluted................................. 32,932 33,072 33,055 32,341 30,654
======= ======= ======== ======== ========

The accompanying notes are an integral part of these consolidated financial
statements.
F-4

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CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS)

[Enlarge/Download Table]

COMMON STOCK TREASURY STOCK TOTAL
------------------ RETAINED ------------------ SHAREHOLDERS'
SHARES AMOUNT EARNINGS SHARES AMOUNT EQUITY
------- -------- --------- ------- -------- -------------

Balance, December 31,
1998..................... 42,804 $ 52,981 $ 64,413 (13,640) $(3,751) $113,643
Net income................. -- -- 16,899 -- -- 16,899
Activity in company stock
plans, net............... 594 4,174 -- -- -- 4,174
Acquisition of Aquatica,
Inc...................... 1,392 16,156 -- -- -- 16,156
------ -------- -------- ------- ------- --------
Balance, December 31,
1999..................... 44,790 73,311 81,312 (13,640) (3,751) 150,872
Net income................. -- -- 23,326 -- -- 23,326
Activity in company stock
plans, net............... 485 5,740 -- -- -- 5,740
Sale of common stock,
net...................... 610 14,787 -- -- -- 14,787
------ -------- -------- ------- ------- --------
Balance, December 31,
2000..................... 45,885 93,838 104,638 (13,640) (3,751) 194,725
Net income................. -- -- 28,932 -- -- 28,932
Activity in company stock
plans, net............... 354 5,267 -- -- -- 5,267
Purchase of treasury
shares................... -- -- -- (143) (2,575) (2,575)
------ -------- -------- ------- ------- --------
Balance, December 31,
2001..................... 46,239 99,105 133,570 (13,783) (6,326) 226,349
Net income (unaudited)..... -- -- 3,001 -- -- 3,001
Activity in company stock
plans, net (unaudited)... 598 3,511 -- -- -- 3,511
Canyon acquisition
(unaudited).............. -- 1,716 -- 181 2,574 4,290
------ -------- -------- ------- ------- --------
Balance, March 31, 2002
(unaudited).............. 46,837 $104,332 $136,571 (13,602) $(3,752) $237,151
====== ======== ======== ======= ======= ========

The accompanying notes are an integral part of these consolidated financial
statements.
F-5

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CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

[Enlarge/Download Table]

THREE MONTHS
ENDED MARCH 31, YEAR ENDED DECEMBER 31,}
------------------- -------------------------------
2002 2001 2001 2000 1999
-------- -------- --------- -------- --------
(UNAUDITED)

Cash flows from operating activities:
Net income........................... $ 3,001 $ 10,774 $ 28,932 $ 23,326 $ 16,899
Adjustments to reconcile net income
to net cash provided by operating
activities--Depreciation and
amortization...................... 6,313 10,394 34,533 30,730 20,615
Deferred income taxes............. 1,196 3,912 15,504 21,085 4,298
Equity in earnings of Aquatica,
Inc............................. -- -- -- -- (600)
Gain on sale of assets............ -- -- (1,881) (3,292) (8,454)
Changes in operating assets and
liabilities:
Accounts receivable, net........ 4,329 4,137 (13,594) 6,723 (16,918)
Other current assets............ 68 4,312 2,760 (4,298) (6,468)
Accounts payable and accrued
liabilities.................. (25,312) (265) 21,263 (1,030) 21,217
Income taxes receivable......... -- 9,323 10,014 (7,256) (430)
Other noncurrent, net........... (241) (2,120) (8,424) (12,287) (4,660)
-------- -------- --------- -------- --------
Net cash (used in) provided
by operating activities.... (10,646) 40,467 89,107 53,701 25,499
-------- -------- --------- -------- --------
Cash flows from investing activities:
Capital expenditures................. (35,703) (19,655) (151,261) (95,124) (77,447)
Purchase of Canyon Offshore, Inc. ... (49,748) -- -- -- --
Purchase of Professional Divers of
New Orleans, Inc., net............ -- (11,500) (11,500) -- --
Cash (restricted) available for
acquisitions...................... -- (30) 2,624 6,062 (8,222)
Investment in Aquatica, Inc.......... -- -- -- -- 442
Prepayments and deposits related to
salvage operations................ -- 782 782 826 7,684
Proceeds from sales of property...... -- -- 1,530 3,124 28,931
Insurance proceeds from loss of
vessel............................ -- -- -- 7,118 --
-------- -------- --------- -------- --------
Net cash used in investing
activities................. (85,451) (30,403) (157,825) (77,994) (48,612)
-------- -------- --------- -------- --------
Cash flows from financing activities:
Exercise of stock warrants and
options, net...................... 3,127 1,791 4,084 2,980 2,043
Purchase of treasury stock........... -- -- (2,575) -- --
Sale of common stock, net of
transaction costs................. -- -- -- 14,787 --
Borrowings under MARAD loan
facility.......................... 14,914 -- 59,494 40,054 --
Borrowings on Line of Credit......... 45,862 -- -- -- --
Repayment of Capital Leases.......... (826) -- -- -- --
-------- -------- --------- -------- --------
Net cash provided by
financing activities....... 63,077 1,791 61,003 57,821 2,043
-------- -------- --------- -------- --------
Net increase (decrease) in cash and
cash equivalents..................... (33,020) 11,855 (7,715) 33,528 (21,070)
Cash and cash equivalents:
Balance, beginning of period......... 37,123 44,838 44,838 11,310 32,380
-------- -------- --------- -------- --------
Balance, end of period............... $ 4,103 $ 56,693 $ 37,123 $ 44,838 $ 11,310
======== ======== ========= ======== ========

The accompanying notes are an integral part of these consolidated financial
statements.
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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, applies to
goodwill and intangible assets arising from transactions completed before and
after the statement's effective date. The Company adopted this standard
effective January 1, 2002, the effect of which was immaterial to CDI's financial
position and results of operations (unaudited).

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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 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 143
to determine the standard's impact, if any, on its financial statements upon
adoption. Among other things SFAS 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):

[Download Table]

ESTIMATED
USEFUL LIFE 2001 2000
----------- -------- --------

Construction in progress........................... N/A $221,916 $111,250
Vessels............................................ 15 103,929 78,776
Offshore leases and equipment...................... UOP 72,157 60,679
Gunnison property under development................ N/A 10,177 --
Machinery, equipment and leasehold improvements.... 5 15,563 15,397
-------- --------
Total property and equipment..................... $423,742 $266,102
======== ========

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 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

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APB Opinion No. 30. The Company adopted this standard effective January 1, 2002,
the effect of which was immaterial to CDI's financial position and results of
operations (unaudited).

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 Corp. (10%);
2000--Enron Corp. (13%); and 1999--EEX Corporation (13%).
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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

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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.

In March 2002 and April 2002, ERT entered into swap contracts which require
payments to (or receipts from) counter parties based on the difference between a
fixed and a variable price for a commodity. The payments under these contracts
will be based on 1,464,000 Mmbtu of natural gas at a fixed price of $3.46/Mcf
over six months and 100,800 barrels of oil at an average fixed price of
$25.87/Bbl. over six months. Management believes these levels represent
approximately one-third of ERT's production over the next six months. Under SFAS
133, we account for these transactions as speculative and record the
transactions as assets or liabilities, as applicable, and record any gain or
loss on settled transactions, and the change in market value, of unsettled
positions at the end of each reporting period in our consolidated statement of
operations. The impact of the swap contracts for the quarter ended March 31,
2002 was immaterial to the financial statements (unaudited).

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
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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 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
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.

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7. ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in thousands):

[Download Table]

2001 2000
------- -------

Accrued payroll and related benefits........................ $ 6,880 $ 5,520
Workers' compensation claims................................ 1,537 559
Workers' compensation claims to be reimbursed............... 6,276 6,133
Royalties payable........................................... 3,207 4,743
Other....................................................... 3,111 4,480
------- -------
Total accrued liabilities......................... $21,011 $21,435
======= =======

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 during the first quarter of 2002 drew an additional $14.9
million (unaudited).

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 in April 2002 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 and March 31, 2002 (unaudited), 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 March 31, 2002, the
Company was in compliance with these covenants (unaudited). As of March 31,
2002, the Company had drawn $45.8 million (unaudited) under this revolving
credit facility. See project financing of Gunnison spar at footnote 10.

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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:

[Download Table]

2001 2000 1999
---- ---- ----

Statutory rate.............................................. 35% 35% 35%
Research and development tax credits........................ (2) (2) (3)
Other....................................................... 2 1 1
-- -- --
Effective rate............................................ 35% 34% 33%
== == ==

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

[Download Table]

2001 2000 1999
------- ------- ------

Current.................................................. $ -- $ -- $4,167
Deferred................................................. 15,504 11,555 4,298
------- ------- ------
$15,504 $11,555 $8,465
======= ======= ======

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):

[Download Table]

2001 2000
-------- -------

Deferred tax liabilities--
Depreciation.............................................. $ 54,631 $38,272
Deferred tax assets--
Reserves, accrued liabilities and other................... (16,122) (9,991)
Valuation allowance (R&D credit).......................... 13,528 8,252
-------- -------
Net deferred tax liability............................. $ 52,037 $36,533
======== =======

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

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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 and March 31, 2002, the
special purpose entity had drawn down $5.6 million and $12.1 million
(unaudited), respectively, 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 and March 31, 2002 (unaudited). This facility has yet to
be syndicated. We are working with the agent of the facility to modify the
facility and are discussing the conversion of the facility to a term loan in a
reduced amount.

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,
$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

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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, one of the Company's subsidiaries entered into a subcontract with
Seacore Marine Contractors Limited to provide the Sea Sorceress to a Coflexip
subsidiary in Canada. Due to difficulties with respect to the sea states and
soil conditions the contract was terminated and an arbitration to recover
damages was commenced. A preliminary liability finding has been made by the
arbitrator against Seacore and in favor of the Coflexip subsidiary. Cal Dive was
not a party to this arbitration proceeding. Only one of the grounds is
potentially applicable to our subsidiary. In the event that Seacore chooses to
seek contribution from our subsidiary which could entail another arbitration, it
is anticipated that the Company's exposure, if any, should be less than
$500,000. In another lengthy 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 defending the litigation vigorously. 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

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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, 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.

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Options outstanding are as follows:

[Enlarge/Download Table]

2001 2000 1999
-------------------- -------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- -------- --------- -------- --------- --------

Options outstanding,
beginning of year.. 2,238,600 $11.34 1,957,208 $ 5.59 2,089,200 $4.70
Granted.............. 589,000 21.84 810,420 19.26 477,938 6.04
Exercised............ (354,838) 9.43 (484,344) 4.24 (585,930) 3.42
Terminated........... (293,516) 15.69 (44,684) 4.10 (24,000) 2.25
--------- ------ --------- ------ --------- -----
Options outstanding,
December 31........ 2,179,246 $13.66 2,238,600 $11.34 1,957,208 $5.59
Options exercisable,
December 31........ 732,787 $ 8.97 518,308 $ 7.10 495,488 $4.30
========= ====== ========= ====== ========= =====

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.

13. BUSINESS SEGMENT INFORMATION

The following summarizes certain financial data by business segment (in
thousands):

[Download Table]

YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------

Revenues--
Subsea and salvage................................. $163,740 $110,217 $128,435
Natural gas and oil production..................... 63,401 70,797 32,519
-------- -------- --------
Total......................................... $227,141 $181,014 $160,954
======== ======== ========
Income from operations--
Subsea and salvage................................. $ 21,705 $ 2,368 $ 15,817
Natural gas and oil production..................... 23,881 32,201 8,207
-------- -------- --------
Total...................................... $ 45,586 $ 34,569 $ 24,024
======== ======== ========

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[Enlarge/Download Table]

YEAR ENDED DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------

Net interest (income) expense and other--
Subsea and salvage................................. $ 739 $ (63) $ (264)
Natural gas and oil production..................... 551 617 (585)
-------- -------- --------
Total...................................... $ 1,290 $ 554 $ (849)
======== ======== ========
Provision for income taxes--
Subsea and salvage................................. $ 7,145 $ 436 $ 5,431
Natural gas and oil production..................... 8,359 11,119 3,034
-------- -------- --------
Total...................................... $ 15,504 $ 11,555 $ 8,465
======== ======== ========
Identifiable assets--
Subsea and salvage................................. $436,085 $301,416 $197,570
Natural gas and oil production..................... 37,037 46,072 46,152
-------- -------- --------
Total...................................... $473,122 $347,488 $243,722
======== ======== ========
Capital expenditures--
Subsea and salvage................................. $131,062 $ 82,697 $ 60,662
Natural gas and oil production..................... 20,199 12,427 16,785
-------- -------- --------
Total...................................... $151,261 $ 95,124 $ 77,447
======== ======== ========
Depreciation and amortization--
Subsea and salvage................................. $ 14,586 $ 11,621 $ 9,459
Natural gas and oil production..................... 19,947 19,109 11,156
-------- -------- --------
Total...................................... $ 34,533 $ 30,730 $ 20,615
======== ======== ========

Three Months Ended March 31, 2002 (unaudited)

[Download Table]

MARCH 31,
2002
---------
(IN THOUSANDS)

Identifiable Assets --
Subsea and salvage........................................ $514,697
Natural gas and oil production............................ 40,765
--------
$555,462
========

With respect to the first quarter of 2002, Canyon Offshore, Inc. (which is
included in the subsea and salvage segment) generated revenues and gross profit
of $8.2 million and $3.0 million, respectively, from the telecommunications
industry. For the three months ended March 31, 2002, Canyon derived $6.8 million
and $2.0 million of its revenues and gross profit, respectively, from Southeast
Asia.

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).

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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.

[Enlarge/Download Table]

AS OF DECEMBER 31,
------------------------------
2001 2000 1999
-------- -------- --------

Gunnison capitalized costs........................... $ 10,177 $ -- $ --
Proved developed properties being amortized.......... 72,157 60,679 49,037
Less--Accumulated depletion, depreciation and
Amortization....................................... (54,482) (35,835) (19,530)
-------- -------- --------
Net capitalized costs........................... $ 27,852 $ 24,844 $ 29,507
======== ======== ========

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:

[Download Table]

YEAR ENDED DECEMBER 31,
---------------------------
2001 2000 1999
------- ------- -------

Proved property acquisition costs....................... $ 4,350 $ 7,635 $22,610
Development costs....................................... 18,247 8,160 5,002
------- ------- -------
Total costs incurred.................................. $22,597 $15,795 $27,612
======= ======= =======

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

[Download Table]

YEAR ENDED DECEMBER 31,
---------------------------
2001 2000 1999
------- ------- -------

Revenues................................................ $63,401 $70,797 $32,519
Production (lifting) costs.............................. 13,236 12,432 9,433
Depreciation, depletion and amortization................ 19,947 19,109 11,156
------- ------- -------
Pretax income from producing activities................. 30,218 39,256 11,930
Income tax expenses..................................... 8,359 11,119 3,034
------- ------- -------
Results of oil and gas producing activities............. $21,859 $28,137 $ 8,896
======= ======= =======

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

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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.

[Download Table]

OIL GAS
RESERVE QUANTITY INFORMATION (MBBLS.) (MMCF.)
---------------------------- -------- -------

Total proved reserves at December 31, 1998.................. 70 22,434
Revisions of previous estimates........................... 1,091 (2,392)
Production................................................ (339) (6,819)
Purchases of reserves in place............................ 888 17,218
Sales of reserves in place................................ (8) (5,060)
----- -------
Total proved reserves at December 31, 1999.................. 1,702 25,381
----- -------
Revisions of previous estimates........................... 24 3,024
Production................................................ (739) (14,959)
Purchases of reserves in place............................ 99 9,416
Sales of reserves in place................................ (5) (1,151)
----- -------
Total proved reserves at December 31, 2000.................. 1,081 21,711
----- -------
Revision of previous estimates............................ 623 4,479
Production................................................ (743) (9,473)
Purchases of reserves in place............................ 53 1,644
Sales of reserves in place................................ -- (22)
Extensions and discoveries................................ 6,844 35,597
----- -------
Total proved reserves at December 31, 2001.................. 7,858 53,936
===== =======

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:

[Enlarge/Download Table]

2001 2000 1999
--------- -------- --------

Future cash inflows................................. $ 261,613 $219,620 $101,686
Future costs--
Production..................................... (46,031) (42,608) (30,550)
Development and abandonment.................... (147,885) (27,690) (30,303)
--------- -------- --------
Future net cash flows before income taxes........... 67,697 149,322 40,833
Future income taxes................................. (24,223) (57,018) (16,191)
--------- -------- --------
Future net cash flows............................... 43,474 92,304 24,642
Discount at 10% annual rate......................... (22,029) (14,591) (1,799)
--------- -------- --------
Standardized measure of discounted future net cash
flows............................................. $ 21,445 $ 77,713 $ 22,843
========= ======== ========

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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:

[Enlarge/Download Table]

2001 2000 1999
-------- -------- --------

Standardized measure, beginning of year.............. $ 77,713 $ 22,843 $ 10,156
Sales, net of production costs....................... (50,165) (57,720) (23,086)
Net change in prices, net of production costs........ (68,811) 87,427 15,968
Changes in future development costs.................. (2,421) (3,695) (1,227)
Development costs incurred........................... 18,247 8,160 5,002
Accretion of discount................................ 3,013 3,785 1,537
Net change in income taxes........................... 30,192 (32,996) (9,776)
Purchases of reserves in place....................... 433 48,229 31,309
Extensions and discoveries........................... 16,612 -- --
Sales of reserves in place........................... 20 2,021 (14,456)
Net change due to revision in quantity estimates..... 1,604 20,084 7,591
Changes in production rates (timing) and other....... (4,992) (20,425) (175)
-------- -------- --------
Standardized measure, end of year.................... $ 21,445 $ 77,713 $ 22,843
======== ======== ========

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):

[Enlarge/Download Table]

2001 2000 1999
------- ------- -------

Beginning balance....................................... $ 1,770 $ 1,789 $ 1,335
Additions............................................... 6,875 4,535 1,923
Deductions.............................................. (4,383) (4,554) (1,469)
------- ------- -------
Ending balance.......................................... $ 4,262 $ 1,770 $ 1,789
======= ======= =======

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.

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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, 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.

[Download Table]

QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

Fiscal 2001
Revenues......................... $58,482 $48,786 $51,570 $68,303
Gross profit..................... 22,258 16,914 13,207 14,532
Net income....................... 10,774 7,546 5,244 5,368
Net income per share:
Basic......................... .33 .23 .16 .17
Diluted....................... .33 .23 .16 .16
Fiscal 2000
Revenues......................... $40,109 $39,901 $49,707 $51,297
Gross profit..................... 8,397 10,418 17,186 19,368
Net income....................... 3,214 3,660 7,686 8,766
Net income per share:
Basic......................... .10 .12 .24 .27
Diluted....................... .10 .11 .24 .27

17. SUBSEQUENT EVENTS (UNAUDITED)

CANYON OFFSHORE, INC. ACQUISITION

In January 2002, CDI purchased Canyon Offshore, Inc. (Canyon), a supplier
of remotely operated vehicles (ROVs) and robotics to the offshore construction
and telecommunications industries. CDI purchased approximately 85% of Canyon's
stock for cash of $52.9 million, the assumption of $9.0 million of Canyon debt
(offset by $3.1 million of cash acquired) 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 committed to purchase the remaining 15% for cash at a price
to be determined by Canyon's performance during the years 2002 through 2004, a
portion of which could be compensation expense. These remaining shares have been
classified as redeemable stock in subsidiary in the accompanying balance sheet
and will be adjusted to their estimated redemption value at each reporting
period prior to redemption based on Canyon's performance. The acquisition was
accounted for as a purchase with the acquisition price allocated to the assets
acquired and liabilities assumed based upon their estimated fair values, with
the excess being recorded as goodwill, which totaled approximately $45.1
million. The allocation of the purchase price to the fair market value of the
net assets acquired in the Canyon acquisition are based on preliminary estimates
of fair market values and may be revised when additional information concerning
asset and liability valuation is obtained; however, management does not
anticipate the adjustments, if any, will have a material impact on the Company's
results of operations or financial position.

F-23

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CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

OFFSHORE PROPERTY ACQUISITION

In April 2002, ERT agreed to acquire a 100% interest in East Cameron Block
374, including existing wells, equipment and improvements. The property, located
in 425 feet of water, is jointly owned by Murphy Exploration & Production
Company and Callon Petroleum Operating Company. Terms include a cash payment to
reimburse the owners for the inception-to-date cost of the subsea wellhead and
umbilical, and an overriding royalty interest in future production. Cal Dive
plans to complete the temporarily abandoned number one well and perform a subsea
tie-back to host platform. The cost of completion and tie-back is estimated at
$7 million with first production expected in September 2002.

F-24

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[CHART OF VESSEL CAPABILITIES]

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[CAL DIVE INTERNATIONAL LOGO]

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Dates Referenced Herein and Documents Incorporated by Reference

		Referenced-On Page
This ‘424B4’ Filing	Date	First	Last	Other Filings

	1/1/03	19	58
	5/28/02	1
Filed on:	5/22/02			8-K
	5/21/02	1	13	8-K
	5/3/02	49
	5/2/02	7	43	8-K
	4/30/02	13	23
	3/31/02	8	69	10-Q
	3/14/02	49
	2/18/02	52		8-K
	2/8/02	37		4
	1/4/02	19
	1/1/02	19	59
	12/31/01	6	72	10-K
	6/30/01	19	57	10-Q
	4/1/01	25	64
	3/31/01	15	51	10-Q
	1/1/01	62
	12/31/00	10	71	10-K
	11/13/00	13	68
	10/30/00	26	68
	3/28/00	37
	3/15/00	37
	12/31/99	10	71	10-K
	8/1/99	62	67
	12/31/98	10	71	10-K, 4
	5/12/98	67		DEF 14A, SC 13G
	12/31/97	10		10-K
	1/1/95	67
	1/1/93	38
				List all Filings

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Filing Submission 0000950129-02-002696 – Alternative Formats (Word / Rich Text, HTML, Plain Text, et al.)

Helix Energy Solutions Group Inc – ‘424B4’ on 5/22/02

On: Wednesday, 5/22/02, at 12:37pm ET · Accession #: 950129-2-2696 · File #: 333-87620

Prospectus — Rule 424(b)(4)Filing Table of Contents

Document Table of Contents

Dates Referenced Herein and Documents Incorporated by Reference

Prospectus — Rule 424(b)(4)
Filing Table of Contents