CAL DIVE INTERNATIONAL INC - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
for the quarterly period ended September 30, 2003

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _____________to ______________

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

Commission File Number: 0-22739

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

Cal Dive International, Inc.
(Exact Name of Registrant as Specified in its Charter)

Minnesota 95-3409686

(State or Other Jurisdiction of (IRS Employer
Incorporation or Organization) Identification Number)

400 N. Sam Houston Parkway E.
Suite 400
Houston, Texas 77060
(Address of Principal Executive Offices)

(281) 618-0400
(Registrant's telephone number,
including area code)

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

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

Yes [X] No [ ]

Indicate by check whether the registrant is an accelerated filer (as defined in
Rule 12b-2 of the Exchange Act).

Yes [X] No [ ]

At November 12, 2003 there were 37,733,708 shares of common stock, no par
value, outstanding.

CAL DIVE INTERNATIONAL, INC.
INDEX

Part I. Financial Information Page

Item 1. Financial Statements

Consolidated Balance Sheets -

September 30, 2003 and December 31, 2002..............................................1

Consolidated Statements of Operations -

Three Months Ended September 30, 2003 and September 30, 2002..........................2

Nine Months Ended September 30, 2003 and September 30, 2002...........................3

Consolidated Statements of Cash Flows -

Nine Months Ended September 30, 2003 and September 30, 2002...........................4

Notes to Consolidated Financial Statements..................................................5

Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.............................................15

Item 3. Quantitative and Qualitative Disclosure about Market Risk.......................24

Item 4. Controls and Procedures.........................................................25

Part II: Other Information

Item 1. Legal Proceedings...... ........................................................25

Item 4. Submission of Matters to a Vote of Security Holders.............................25

Item 5. Other Information...............................................................26

Item 6. Exhibits and Reports on Form 8-K................................................26

Signatures.................................................................................27

PART I. FINANCIAL STATEMENTS

Item 1. Financial Statements

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
(UNAUDITED)

Sept. 30, Dec. 31,
2003 2002
--------- --------
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 2,712 $ 0
Restricted cash 2,432 2,506
Accounts receivable --
Trade, net of revenue allowance on gross
amounts billed of $7,631 and $7,156 90,424 65,743
Unbilled 6,677 9,675
Other current assets 33,150 38,195
-------- --------
Total current assets 135,395 116,119
-------- --------

PROPERTY AND EQUIPMENT 769,837 726,878
Less - Accumulated depreciation (166,495) (130,527)
-------- --------
603,342 596,351
-------- --------
OTHER ASSETS:
Goodwill 80,228 79,758
Investment in Deepwater Gateway LLC 34,373 32,688
Other assets, net 17,057 15,094
-------- --------
$870,395 $840,010
======== ========

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 54,756 $ 62,798
Accrued liabilities 37,282 34,790
Current maturities of long-term debt 14,109 4,201
-------- --------
Total current liabilities 106,147 101,789
LONG-TERM DEBT, net of current maturities 215,439 223,576
DEFERRED INCOME TAXES 87,540 75,208
DECOMMISSIONING LIABILITIES 66,673 92,420
OTHER LONG-TERM LIABILITIES 2,025 1,972
-------- --------
Total Liabilities 477,824 494,965
REDEEMABLE STOCK IN SUBSIDIARY 0 7,528
CONVERTIBLE PREFERRED STOCK 24,437 0
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY:
Common stock, no par, 60,000 shares
authorized, 51,292 and 51,060 shares issued
and outstanding 199,285 195,405
Retained earnings 169,833 145,947
Treasury stock, 13,602 and 13,602 shares, at cost (3,741) (3,741)
Accumulated other comprehensive income (loss) 2,757 (94)
-------- --------
Total shareholders' equity 368,134 337,517
-------- --------
$870,395 $840,010
======== ========

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

1

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)

Three Months Ended Sept. 30,
----------------------------
2003 2002
---------- ----------

NET REVENUES:
Marine contracting $ 69,897 $ 68,102
Oil and gas production 33,958 15,913
-------- --------
103,855 84,015

COST OF SALES:
Marine contracting 62,530 63,322
Oil and gas production 17,320 9,120
-------- --------
GROSS PROFIT 24,005 11,573

Selling and administrative expenses 8,620 6,372
-------- --------

INCOME FROM OPERATIONS 15,385 5,201

OTHER EXPENSE:
Interest expense, net 639 424
Other, net 216 235
-------- --------

INCOME BEFORE INCOME TAXES 14,530 4,542
Provision for income taxes 5,231 1,590
-------- --------

NET INCOME 9,299 2,952
Preferred stock dividends and accretion 362 0
-------- --------

NET INCOME APPLICABLE TO COMMON SHAREHOLDERS $ 8,937 $ 2,952
======== ========

NET INCOME PER COMMON SHARE:
Basic $ 0.24 $ 0.08
Diluted $ 0.24 $ 0.08
======== ========

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic 37,665 37,268
Diluted 37,776 37,432
======== ========

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

2

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)

Nine Months Ended Sept. 30,
-----------------------------
2003 2002
---------- ----------

NET REVENUES:
Marine contracting $193,108 $172,132
Oil and gas production 101,486 38,116
-------- --------
294,594 210,248

COST OF SALES:
Marine contracting 176,319 149,838
Oil and gas production 50,877 20,534
-------- --------
GROSS PROFIT 67,398 39,876

Selling and administrative expenses 26,201 18,869
-------- --------

INCOME FROM OPERATIONS 41,197 21,007

OTHER (INCOME) EXPENSE:
Interest expense, net 2,176 1,224
Other, net 858 (474)
-------- --------

INCOME BEFORE INCOME TAXES 38,163 20,257
Provision for income taxes 13,739 7,090
-------- --------

INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE 24,424 13,167
Cumulative effect of change in accounting principle, net 530 0
-------- --------

NET INCOME 24,954 13,167
Preferred stock dividends and accretion 1,068 0
-------- --------

NET INCOME APPLICABLE TO COMMON SHAREHOLDERS $ 23,886 $ 13,167
======== ========

NET INCOME PER COMMON SHARE:
Basic:
Net income before change in accounting principle $ 0.62 $ 0.38
Cumulative effect of change in accounting principle $ 0.01 $ 0.00
-------- --------
Net income applicable to common shareholders $ 0.63 $ 0.38
======== ========

Diluted:
Net income before change in accounting principle $ 0.62 $ 0.37
Cumulative effect of change in accounting principle $ 0.01 $ 0.00
-------- --------
Net income applicable to common shareholders $ 0.63 $ 0.37
======== ========

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic 37,618 34,888
Diluted 37,715 35,231
======== ========

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

3

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)

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

4

CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1 - Basis of Presentation

The accompanying financial statements include the accounts of Cal Dive
International, Inc. (Cal Dive, CDI or the Company) and its majority owned
subsidiaries. The Company accounts for its 50% interest in Deepwater Gateway LLC
using the equity method of accounting as the Company does not have voting or
operational control of this entity. All material intercompany accounts and
transactions have been eliminated. These financial statements are unaudited,
have been prepared pursuant to instructions for the Quarterly Report on Form
10-Q required to be filed with the Securities and Exchange Commission and do not
include all information and footnotes normally included in annual financial
statements prepared in accordance with generally accepted accounting principles.

Management has reflected all adjustments (which were normal recurring
adjustments) that it believes are necessary for a fair presentation of the
consolidated balance sheets, results of operations, and cash flows, as
applicable. Operating results for the period ended September 30, 2003, are not
necessarily indicative of the results that may be expected for the year ending
December 31, 2003. The Company's balance sheet as of December 31, 2002 included
herein has been derived from the audited balance sheet as of December 31, 2002
included in the Company's 2002 Annual Report on Form 10-K/A. These financial
statements should be read in conjunction with the annual consolidated financial
statements and notes thereto included in the Company's 2002 Annual Report on
Form 10-K/A.

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

Note 2 - Accounting for Asset Retirement Obligations

On January 1, 2003, the Company adopted Statement of Financial
Accounting Standards (SFAS) 143, Accounting for Asset Retirement Obligations,
which addresses the financial accounting and reporting obligations and
retirement costs related to the retirement of tangible long-lived assets. Among
other things, SFAS 143 requires oil and gas companies to reflect decommissioning
liabilities on the face of the balance sheet at fair value on a discounted
basis. Prior to January 1, 2003, the Company reflected this liability on the
balance sheet on an undiscounted basis.

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

The pro forma effects of the application of SFAS 143 as if the
statement had been adopted on January 1, 2002 are presented below (in
thousands):

5

The following table describes the changes in the Company's asset
retirement obligations for the first nine months of 2003 (in thousands):

Asset retirement obligation at December 31, 2002 ..................... $ 92,420
Cumulative effect adjustment ......................................... (26,527)
---------
Asset retirement obligation at January 1, 2003 ....................... 65,893
Liability incurred during the period ................................. 3,737
Liabilities settled during the period ................................ (5,603)
Accretion expense .................................................... 2,646
---------
Asset retirement obligation at September 30, 2003 ................... $ 66,673
=========

The pro forma asset retirement obligation liability balances as if SFAS
143 had been adopted January 1, 2002 are as follows (in thousands):

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

6

Note 3 - New Accounting Pronouncements

In January 2003, Financial Accounting Standards Board Interpretation
No. 46, Consolidation of Variable Interest Entities ("FIN No. 46"), was issued.
FIN No. 46 requires companies that control another entity through interest other
than voting interests to consolidate the controlled entity. FIN No. 46 applies
immediately to variable interest entities created after January 31, 2003. For
variable interest entities created before February 1, 2003, FIN No. 46 is
applied no later than the end of the first reporting period ending after
December 15, 2003. The Interpretation requires certain disclosures in financial
statements issued after January 31, 2003, if it is reasonably possible that the
Company will consolidate or disclose information about variable interest
entities when the Interpretation becomes effective. The Company is currently
evaluating the impact the adoption will have on its consolidated financial
statements.

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

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity ("SFAS
No. 150"). SFAS No. 150 requires that certain financial instruments, which under
previous guidance were accounted for as equity, must now be accounted for as
liabilities. The financial instruments affected include mandatorily redeemable
stock, certain financial instruments that require or may require the issuer to
buy back some of its shares in exchange for cash or other assets and certain
obligations that can be settled with shares of stock. SFAS No. 150 is effective
for all financial instruments entered into or modified after May 31, 2003 and
must be applied to the Company's existing financial instruments effective July
1, 2003. The Company adopted SFAS No. 150 as required effective July 1, 2003. As
a result of this adoption, the Company reclassified the $4.9 million of
Redeemable Stock in Subsidiary (see discussion in Note 12) from mezzanine
classification (i.e., between liabilities and shareholders equity on the balance
sheet) to long-term debt, along with the applicable amount in current maturities
of long-term debt. The adoption had no other impact on the Company's
consolidated financial statements.

Note 4 - Comprehensive Income

The components of total comprehensive income for the three and nine
months ended September 30, 2003, respectively are as follows (in thousands):

Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2002 2003 2002
-------- ------- -------- --------

Net Income ................................................. 9,299 $ 2,952 $ 24,954 $ 13,167
Cumulative translation adjustment, net ..................... (690) 549 657 549
Unrealized gain (loss) on commodity hedges, net ............ 3,990 (1,230) 2,194 (1,230)
-------- ------- -------- --------

Total comprehensive income ................................. 12,599 $ 2,271 $ 27,805 $ 12,486
======== ======= ======== ========

7

The components of accumulated other comprehensive loss are as follows
(in thousands):

Sept. 30, Dec. 31,
2003 2002
--------- --------

Cumulative translation adjustment, net.................................. $ 3,205 $ 2,548
Unrealized loss on commodity hedges, net................................ (448) (2,642)
-------- --------
Accumulated other comprehensive income (loss)........................... $ 2,757 $ (94)
======== ========

Note 5 - Derivatives

The Company's price risk management activities involve the use of
derivative financial instruments. The Company uses derivative financial
instruments with respect to a portion of its oil and gas production to achieve a
more predictable cash flow by reducing its exposure to price fluctuations. These
transactions generally are swaps or collars and are entered into with major
financial institutions or commodities trading institutions. These derivative
financial instruments are intended to reduce the Company's exposure to declines
in the market prices of natural gas and crude oil that the Company produces and
sells and to manage cash flow in support of the Company's annual capital
expenditure budget. Under SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities, all derivatives are reflected in our balance sheet at
their fair market value.

Under SFAS No. 133 there are two types of hedging activities: hedges of
cash flow exposure and hedges of fair value exposure. The Company engages
primarily in cash flow hedges. Hedges of cash flow exposure are entered into to
hedge a forecasted transaction or the variability of cash flows to be received
or paid related to a recognized asset or liability. Changes in the derivative
fair values that are designated as cash flow hedges are deferred to the extent
they are effective and are recorded as a component of accumulated other
comprehensive income until the hedged transactions occur and are recognized in
earnings. The ineffective portion of a cash flow hedge's change in fair value is
recognized immediately in earnings in oil and gas production revenues.

As required by SFAS No. 133, we formally document all relationships
between hedging instruments and hedged items, as well as our risk management
objectives, strategies for undertaking various hedge transactions and our
methods for assessing and testing correlation and hedge ineffectiveness. All
hedging instruments are linked to the hedged asset, liability, firm commitment
or forecasted transaction. We also assess, both at the inception of the hedge
and on an on-going basis, whether the derivatives that are used in our hedging
transactions are highly effective in offsetting changes in cash flows of the
hedged items. We discontinue hedge accounting prospectively if we determine that
a derivative is no longer highly effective as a hedge.

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

During the second half of 2002 and first nine months of 2003, the
Company entered into various cash flow hedging swap contracts and a costless
collar contract to fix cash flows relating to a portion of the Company's oil and
gas production. All of these qualify for hedge accounting and none extend beyond
a year. The aggregate fair value of the swaps was a liability of $688,000 as of
September 30, 2003. The Company recorded $448,000 of unrealized loss, net of
taxes of $240,000, in other comprehensive loss within shareholders' equity as
these hedges were highly effective. During the third quarter of 2003, the
Company reclassified approximately $2.4 million of losses from other
comprehensive loss to oil and gas production revenues upon settlement of such
contracts.

As of September 30, 2003, the Company had the following volumes under
derivative contracts related to its oil and gas producing activities:

8

Note 6 - Foreign Currency

The functional currency for the Company's foreign subsidiary Well Ops
(U.K.) Limited is the applicable local currency (British Pound). Results of
operations for this subsidiary are translated into U.S. dollars using average
exchange rates during the period. Assets and liabilities of this foreign
subsidiary are translated into U.S. dollars using the exchange rate in effect at
the balance sheet date and the resulting translation adjustment, which was a
loss of $690,000, net of taxes of $370,000, in the third quarter of 2003 is
included in accumulated other comprehensive income (loss), a component of
shareholders' equity. All foreign currency transaction gains and losses are
recognized currently in the statements of operations. These amounts for the
quarter ended September 30, 2003 were not material to the Company's results of
operations or cash flows.

Canyon Offshore, the Company's ROV and robotics subsidiary, has
operations in the United Kingdom and Southeast Asia sectors. Canyon conducts the
majority of its affairs in these regions in U.S. dollars which it considers the
functional currency. When currencies other than the U.S. dollar are to be paid
or received the resulting gain or loss from translation is recognized in the
statements of operations. These amounts for the quarter ended September 30, 2003
were not material to the Company's results of operations or cash flows.

Note 7 - Earnings Per Share

The Company computes and presents earnings per share ("EPS") 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 and the income included in the
numerator excludes the effects of the impact of dilutive common stock
equivalents, if any. The computation of the basic and diluted per share amounts
for the Company's were as follows (in thousands, except per share):

9

Stock options to purchase approximately 1.1 million shares for the
three months and nine months ended September 30, 2003 and 912,000 and 260,000
shares for the three months and nine months ended September 30, 2002,
respectively, were not dilutive and, therefore, were not included in the
computations of diluted income per common share amounts. In addition,
approximately 1.1 million shares attributable to the convertible preferred stock
were excluded from the three months and nine months ended September 30, 2003,
calculation of diluted EPS, as the effect was antidilutive.

Note 8 - Stock Based Compensation Plans

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

10

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.

For the purposes of pro forma disclosures, the fair value of each
option grant is estimated on the date of grant using the Black-Scholes option
pricing model with the following weighted average assumptions used: expected
dividend yields of 0 percent; expected lives ranging from three to ten years,
risk-free interest rate assumed to be 4.0 percent in 2002 and 3.8 percent in
2003, and expected volatility to be 59 percent in 2002 and in 2003. The fair
value of shares issued under the Employee Stock Purchase Plan was based on the
15 percent discount received by the employees. The weighted average per share
fair value of the options granted during the nine months ended September 30,
2003 and 2002 was $12.63 and $15.20, respectively. The estimated fair value of
the options is amortized to pro forma expense over the vesting period.

Note 9 - Business Segment Information (in thousands)

During the first quarter of 2003 the Company changed the name of its
Subsea and Salvage segment to Marine Contracting. This change had no impact on
amounts reported.

During the quarters ended September 30, 2003 and 2002, respectively,
the Company derived $15.9 million and $17.7 million respectively of its revenues
from the U.K. sector utilizing $112.2 million and $89.3 million, respectively of
its total assets in this region. Additionally, $7.1 million and $21.8 million of
revenues were derived from the Latin America sector during the three months
ended September 30, 2003 and 2002, respectively. The majority of the remaining
revenues were generated in the U.S. Gulf of Mexico. Marine Contracting revenues
from alliance partner Horizon Offshore, Inc. were $7.8 million and $4.7 million
during the three months ended September 30, 2003 and 2002, respectively. This
level represented 11% and 7%, respectively of Marine Contracting revenues for
the three months ended September 30, 2003 and 2002, respectively.

Note 10 - Long-Term Financings

At September 30, 2003, $139.4 million was outstanding on our long-term
financing for construction of the Q4000. This U.S. Government guaranteed
financing is pursuant to Title XI of the

11

Merchant Marine Act of 1936 which is administered by the Maritime Administration
("MARAD Debt"). The MARAD Debt is payable in equal semi-annual installments
which began in August 2002 and matures 25 years from such date. It is
collateralized by the Q4000, with CDI guaranteeing 50% of the debt, and bears
interest at a rate which currently floats at a rate approximating AAA Commercial
Paper yields plus 20 basis points (approximately 1.5% as of September 30, 2003).
For a period up to ten years from delivery of the vessel in April 2002, CDI has
the ability to lock in a fixed rate. In accordance with the MARAD Debt
agreements, CDI is required to comply with certain covenants and restrictions,
including the maintenance of minimum net worth, working capital and
debt-to-equity requirements. As of September 30, 2003, the Company was in
compliance with these covenants.

The Company has a $70 million revolving credit facility due in 2005.
This facility is collateralized by accounts receivable and certain of the
Company's Marine Contracting vessels, bears interest at LIBOR plus 125-250 basis
points depending on CDI leverage ratios (approximately 3.4% as of September 30,
2003) and, among other restrictions, includes three financial covenants (cash
flow leverage, minimum interest coverage and fixed charge coverage). As of
September 30, 2003, the Company had drawn $35.9 million under this revolving
credit facility and was in compliance with these covenants.

In November 2001, Energy Resource Technology, Inc. (a wholly owned
subsidiary, "ERT") (with a corporate guarantee by CDI) entered into a five-year
lease transaction with an entity owned by a third party to fund CDI's portion of
the construction costs ($67 million) of the spar for the Gunnison field. As of
June 30, 2002, the entity had drawn down $22.8 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. In August 2002,
CDI acquired 100% of the equity of the entity and converted the notes into a
term loan. The total commitment of the loan was reduced to $35 million and will
be payable in quarterly installments of $1.75 million for three years after
delivery of the spar with the remaining $15.75 million due at the end of the
three years. The facility bears interest at LIBOR plus 225-300 basis points
depending on CDI leverage ratios (approximately 3.6% as of September 30, 2003)
and includes, among other restrictions, three financial covenants (cash flow
leverage, minimum interest coverage and debt to total book capitalization). As
of September 30, 2003 the Company had drawn down $35.0 million on the facility
and was in compliance with these covenants.

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

Scheduled maturities of Long-term Debt outstanding as of September 30,
2003 were as follows (in thousands):

12

The Company capitalized interest totaling $1.7 million and $1.2 million
during the nine months ended September 30, 2003 and 2002, respectively.

Note 11 - Litigation and Claims

The Company is involved in various routine legal proceedings primarily
involving claims for personal injury under the General Maritime Laws of the
United States and 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. During 2002, the Company was engaged in a large
construction project, where supports engineered by a subcontractor failed
resulting in over a month of downtime for two of CDI's vessels. Management
believes that under the terms of the contract the Company is entitled to the
contractual stand-by rate for the vessels during their downtime. The customer is
currently disputing these invoices along with certain other change orders. CDI
has billed approximately $34.0 million ($9.7 million of which had not been
collected as of September 30, 2003) for this project which management believes
it is due under the terms of the contract. However, due to the size of the
dispute and inherent uncertainties with respect to an arbitration, CDI provided
a reserve in the fourth quarter of 2002 resulting in a loss for the Company on
the project as a whole.

In 1998, one of our subsidiaries entered into a subcontract with
Seacore Marine Contractors Limited ("Seacore") to provide the Sea Sorceress to a
Coflexip subsidiary in Canada ("Coflexip"). Due to difficulties with respect to
the sea states and soil conditions the contract was terminated and an
arbitration to recover damages was commenced. A preliminary liability finding
has been made by the arbitrator against Seacore and in favor of the Coflexip
subsidiary. We were not a party to this arbitration proceeding. Seacore and
Coflexip settled this matter prior to the conclusion of the arbitration
proceeding with Seacore paying Coflexip $6.95 million (Canadian). Seacore has
initiated an arbitration proceeding against Cal Dive Offshore Ltd. ("CDO"), a
subsidiary of Cal Dive, seeking contribution. Because only one of the grounds in
the preliminary findings by the arbitrator is applicable to CDO, and because CDO
holds substantial counterclaims against Seacore, it is anticipated that our
subsidiary's exposure, if any, should be less than $500,000.

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

Note 12 - Canyon Offshore

In January 2002, CDI purchased Canyon, a supplier of remotely operated
vehicles (ROVs) and robotics to the offshore construction and telecommunications
industries. CDI purchased Canyon for cash of $52.8 million, the assumption of
$9.0 million of Canyon debt (offset by $3.1 million of cash acquired), 181,000
shares of CDI common stock valued at $4.3 million (143,000 shares of which we
purchased as treasury shares during the fourth quarter of 2001) and a commitment
to purchase the redeemable stock in Canyon at a price to be determined by
Canyon's performance during the years 2002 through 2004 from continuing
employees at a minimum purchase price of $13.53 per share (or $7.5 million). The
Company also agreed to make future payments relating to the tax impact on the
date of redemption, whether employment continued or not. As they are employees,
any share price paid in excess of the $13.53 per share and related tax impact
will be recorded as compensation expense. These remaining shares have been
classified as redeemable stock in subsidiary (long-term debt beginning in the
third quarter of 2003 - see note 3) in the accompanying balance sheet and will
be adjusted to their estimated redemption value at each reporting period based
on Canyon's performance. In April 2003, the Company purchased

13

approximately one-third of the redeemable shares at the minimum purchase price
of $13.53 per share. Consideration included approximately $400,000 of contingent
consideration relating to tax gross-up payments paid to the Canyon employees in
accordance with the purchase agreement. This amount was recorded as goodwill in
the period paid (i.e., the second quarter of 2003).

Note 13 - Offshore Property Acquisitions

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

Note 14 - Convertible Preferred Stock

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

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

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

14

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.

FORWARD LOOKING STATEMENTS AND ASSUMPTIONS

This Quarterly Report on Form 10-Q includes certain statements that may
be deemed "forward looking statements" under applicable law. Forward looking
statements and assumptions in this Form 10-Q that are not statements of
historical fact involve risks and assumptions that could cause actual results to
vary materially from those predicted, including among other things, unexpected
delays and operational issues associated with turnkey projects, the price of
crude oil and natural gas, offshore weather conditions, change in site
conditions, and capital expenditures by customers. The Company strongly
encourages readers to note that some or all of the assumptions, upon which such
forward looking statements are based, are beyond the Company's ability to
control or estimate precisely, and may in some cases be subject to rapid and
material change. For a complete discussion of risk factors, we direct your
attention to our Annual Report on Form 10-K/A for the year ended December 31,
2002, filed with the Securities and Exchange Commission.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of
operations are based upon our consolidated financial statements. We prepare
these financial statements in conformity with accounting principles generally
accepted in the United States. As such, we are required to make certain
estimates, judgments and assumptions that affect the reported amounts of assets
and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the periods presented. We base our estimates on
historical experience, available information and various other assumptions we
believe to be reasonable under the circumstances. These estimates may change as
new events occur, as more experience is acquired, as additional information is
obtained and as our operating environment changes. There have been no material
changes or developments in our evaluation of the accounting estimates and the
underlying assumptions or methodologies that we believe to be Critical
Accounting Policies and Estimates as disclosed in our Form 10-K/A for the year
ending December 31, 2002 except for the adoption of SFAS 143, Accounting for
Asset Retirement Obligations, on January 1, 2003 and SFAS 150, Accounting for
Certain Financial Instruments with characteristics of both Liabilities and
Equity on July 1, 2003.

SFAS 143, addresses the financial accounting and reporting obligations
and retirement costs related to the retirement of tangible long-lived assets.
Among other things, SFAS 143 requires oil and gas companies to reflect
decommissioning liabilities on the face of the balance sheet at fair value on a
discounted basis. Historically, ERT has reflected this liability on the balance
sheet on an undiscounted basis.

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

SFAS No. 150 requires that certain financial instruments, which under
previous guidance were accounted for as equity, must now be accounted for as
liabilities. The financial instruments affected include mandatorily redeemable
stock, certain financial instruments that require or may require the issuer to
buy back some of its shares in exchange for cash or other assets and certain
obligations that can be settled with shares of stock. SFAS No. 150 is effective
for all financial instruments entered into or modified after May 31, 2003 and
must be applied to the Company's existing financial instruments effective July
1, 2003. The Company adopted SFAS No. 150 as required effective July 1, 2003.
As a

15

result of this adoption, the Company reclassified the $4.9 million of Redeemable
Stock in Subsidiary (see discussion in Note 12 to consolidated financial
statements) from mezzanine classification (i.e., between liabilities and
shareholders equity on the balance sheet) to long-term debt, along with the
applicable amount in current maturities of long-term debt. Otherwise, the
adoption had no impact on the Company's consolidated financial statements.

RESULTS OF OPERATIONS

Comparison of Three Months Ended September 30, 2003 and 2002

Revenues. During the three months ended September 30, 2003, the
Company's revenues increased 24% to $103.9 million compared to $84.0 million for
the three months ended September 30, 2002. Of the overall $19.8 million
increase, $18.0 million was generated by the Oil and Gas Production segment due
to increased production and higher oil and gas prices.

Oil and Gas Production revenue for the three months ended September 30,
2003 increased $18.0 million, or 113%, to $34.0 million from $15.9 million
during the comparable prior year period. The average realized natural gas price
of $4.61 per Mcf, net of hedges in place, during the third quarter of 2003 was
41% higher than the $3.28 per Mcf realized in the comparable prior year quarter
while average realized oil prices, net of hedges in place, increased 20% to
$27.41 per barrel compared to $26.87 per barrel realized during the third
quarter of 2002. The 64% increase in production (7.2 Bcfe for the three months
ended September 30, 2003 compared to 4.4 Bcfe in the third quarter of 2002) is a
result of the four significant property acquisitions completed last year.

Gross Profit. Gross profit of $24.0 million for the third quarter of
2003 represents a 107% increase compared to the $11.6 million recorded in the
comparable prior year period with the Oil and Gas Production segment
contributing 79% of the increase. Marine Contracting gross profit increased $2.6
million, or 54%, to $7.4 million for the three months ended September 30, 2003,
from $4.8 million in the prior year period. This increase was primarily the
result of improved utilization in the deepwater contracting group (78% for the
third quarter of 2003 versus 71% for the third quarter of 2002, resulting in a
$2.2 million increase in gross profit), with most of that utilization being
achieved outside of the U.S. Gulf of Mexico, and Canyon's gross profit
increasing $2.4 million as the result of several pipeline burial projects during
the third quarter of 2003, which included deployment of the new T750 trenching
unit. These increases were partially offset by a decline in gross profit for the
Seawell (Well Ops UK Ltd) as pricing in the North Sea has deteriorated due to a
lack of both construction and drilling activity. Also partially offsetting these
increases was an increase in costs associated with a new offshore insurance
package which commenced July 1, 2003. Oil and gas production gross profit
increased $9.8 million, or 145%, due to significantly higher levels of
production and to commodity price increases.

Gross margins of 23% in the third quarter of 2003 were nine points
better than the 14% in the prior year period. Marine Contracting margins
increased four points to 11% for the three months ended September 30, 2003, from
7% in the comparable prior year quarter, due to the factors noted above. In
addition, margins in the Oil and Gas Production segment increased six points to
49% for the three months ended September 30, 2003, from 43% in the year ago
quarter, due to the higher average realized commodity prices discussed above and
to improved efficiency in the operations of our offshore facilities.

Selling & Administrative Expenses. Selling and administrative expenses
of $8.6 million for the three months ended September 30, 2003 were $2.2 million
higher than the $6.4 million incurred in the third quarter of 2002 due primarily
to an increase in the costs associated with the ERT Incentive Program (which is
tied directly to the Oil and Natural Gas Production segment profitability that
was significantly higher in the third quarter of 2003 compared to the third
quarter of 2002). Overhead at 8% of revenues for the third quarter held steady
as compared to the comparable prior year period.

16

Other (Income) Expense. The Company reported other expense of $855,000
for the three months ended September 30, 2003 compared to other expense of
$659,000 for the three months ended September 30, 2002. Net interest expense of
$639,000 in the third quarter of 2003 is higher than the $424,000 incurred in
the three months ended September 30, 2002 due to higher debt levels.

Income Taxes. Income taxes increased to $5.2 million for the three
months ended September 30, 2003 compared to $1.6 million in the comparable prior
year period due to increased profitability. The effective rate increased to 36%
in the third quarter of 2003 compared to 35% in 2002 due to provisions for
foreign taxes.

Net Income. Net income of $8.9 million for the three months ended
September 30, 2003 was $6.0 million greater than the comparable period in 2002
as a result of factors described above.

Comparison of Nine Months Ended September 30, 2003 and 2002

Revenues. During the nine months ended September 30, 2003, revenues
increased $84.3 million, or 40%, to $294.6 million compared to $210.2 million
for the nine months ended September 30, 2002. The Marine Contracting segment
contributed $21.0 million of the increase, primarily the result of the
acquisition of the Seawell during the third quarter of 2002. In addition, the
Q4000 and the Intrepid worked a full nine months in 2003 as compared to six
months in the prior year period as these vessels were placed in service in the
second quarter of 2002.

Oil and Gas Production revenue for the nine months ended September 30,
2003 increased $63.4 million, or 166%, to $101.5 million from $38.1 million
during the comparable prior year period. The increase was due to a 40% increase
in our average realized commodity prices to $4.80 per Mcfe, net of hedges in
place ($4.94 per Mcf of natural gas and $27.58 per barrel of oil) in the first
nine months of 2003 from $3.43 per Mcfe ($3.08 per Mcf of natural gas and $24.56
per barrel of oil) in the nine months ended September 30, 2002. Production
essentially doubled to 20.7 Bcfe during the first nine months of 2003 from 10.4
Bcfe during the comparable prior year period as a result of the property
acquisitions during the third quarter of 2002.

Gross Profit. Gross profit of $67.4 million for the first nine months
of 2003 was $27.5 million, or 69%, greater than the $39.9 million gross profit
recorded in the comparable prior year period due entirely to the revenue
increase in Oil and Gas Production mentioned above. Oil and Gas Production gross
profit increased $33.0 million from $17.6 million in the first nine months of
2002 to $50.6 million for the nine months ended September 30, 2003, due to the
increases in average realized commodity prices and production described above.
Offsetting this increase was a 25% decrease in the Marine Contracting segment
gross profit to $16.8 million for the nine months ended September 30, 2003 from
$22.3 million in the comparable prior year period. This decline is primarily due
to a decrease in Well Ops (U.K.) Limited's results from $4.5 million in the
first nine months of 2002 to essentially breakeven for the comparable period in
2003 due to the aforementioned pricing pressures in the North Sea market.

Gross margins improved to 23% for the nine months ended September 30,
2003 compared to 19% during the nine months ended September 30, 2002 due
primarily to the aforementioned increases in average realized commodity prices.
Marine Contracting margins decreased from 13% for the first nine months of 2002
to 9% during the first nine months of 2003 due mainly to the depressed markets
for offshore construction in the GOM and the North Sea, increased competition in
the OCS market and increased offshore insurance costs.

Selling & Administrative Expenses. Selling and administrative expenses
were $26.2 million in the first nine months of 2003, which is 39% more than the
$18.9 million incurred in the first nine months of 2002, primarily due to the
addition of business units acquired and higher ERT incentive accruals. Overhead
at 9% of revenues for the nine months ended September 30, 2003 held steady as
compared to the comparable prior year period.

17

Other (Income) Expense. The Company reported other expense of $3.0
million for the nine months ended September 30, 2003 in contrast to $750,000 for
the nine months ended September 30, 2002. Included in other expense for the
first nine months of 2002 is a $1.1 million gain on our foreign currency
derivative associated with the acquisition of Well Ops (U.K.) Limited recorded
in other income in June 2002. Net interest expense of $2.2 million for the first
nine months of 2003 is higher than the $1.2 million in the comparable prior year
period as a result of our higher debt levels and the reduction of capitalized
interest expense as the Q4000 and Intrepid were in service for only the second
and third quarters of the 2002 period.

Income Taxes. Income taxes increased to $13.7 million for the nine
months ended September 30, 2003, compared to $7.1 million in the comparable
prior year period due to increased profitability. The effective rate increased
to 36% in the first nine months of 2003 compared to 35% in 2002 due to
provisions for foreign taxes.

Net Income. Net income of $23.9 million for the nine months ended
September 30, 2003 was $10.7 million, or 81%, greater than the comparable period
in 2002 as a result of factors described above.

18

LIQUIDITY AND CAPITAL RESOURCES

During the three years following our initial public offering in 1997,
internally generated cash flow funded approximately $164 million of capital
expenditures and enabled us to remain essentially debt-free. In August 2000, we
closed the long-term MARAD financing for construction of the Q4000. This U.S.
Government guaranteed financing is pursuant to Title XI of the Merchant Marine
Act of 1936 which is administered by the Maritime Administration. We refer to
this debt as MARAD Debt. Through September 30, 2003, we have drawn $143.5
million on this facility. In January 2002, we acquired Canyon Offshore, Inc., in
July 2002 we acquired the Well Operations Business Unit of Technip-Coflexip and
in August 2002, ERT made two significant property acquisitions (see further
discussion below). These acquisitions significantly increased our debt to total
book capitalization ratio from 31% at December 31, 2001 to 40% at December 31,
2002. Additionally, increased operations coupled with depressed market
conditions caused our working capital to decrease from $48.6 million at December
31, 2001 to $14.3 million at December 31, 2002. In order to reduce this
leverage, on January 8, 2003, CDI completed the private placement of $25 million
of a newly designated class of cumulative convertible preferred stock (Series
A-1 Cumulative Convertible Preferred Stock, par value $0.01 per share) which is
convertible into 833,334 shares of Cal Dive common stock at $30 per share. As of
September 30, 2003 our debt to total book capitalization had declined to 37% and
working capital had increased to $29.2 million.

Derivative Activities. The Company's price risk management activities
involve the use of derivative financial instruments to hedge the impact of
market price risk exposures which currently relate to our oil and gas
production. Under SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, all derivatives are reflected in our balance sheet at their
fair value.

Under SFAS No. 133 there are two types of hedging activities: hedges of
cash flow exposure and hedges of fair value exposure. The Company engages
primarily in cash flow hedges. Hedges of cash flow exposure are entered into to
hedge a forecasted transaction or the variability of cash flows to be received
or paid related to a recognized asset or liability. Changes in the derivative
fair values that are designated as cash flow hedges are deferred to the extent
that they are effective and are recorded as a component of accumulated other
comprehensive income until the hedged transactions occur and are recognized in
earnings. The ineffective portion of a cash flow hedge's change in value is
recognized immediately in earnings in oil and gas production revenues.

As required by SFAS No. 133, we formally document all relationships
between hedging instruments and hedged items, as well as our risk management
objectives, strategies for undertaking various hedge transactions and our
methods for assessing and testing correlation and hedge ineffectiveness. All
hedging instruments are linked to the hedged asset, liability, firm commitment
or forecasted transaction. We also assess, both at the inception of the hedge
and on an on-going basis, whether the derivatives that are used in our hedging
transactions are highly effective in offsetting changes in cash flows of the
hedged items. We discontinue hedge accounting prospectively if we determine that
a derivative is no longer highly effective as a hedge.

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

During the second half of 2002 and first nine months of 2003, the
Company entered into various cash flow hedging swap contracts and a costless
collar to fix cash flows relating to a portion of the Company's oil and gas
production. All of these qualified for hedge accounting and none extend beyond a
year. The aggregate fair market value of the swaps was a liability of $688,000
as of September 30, 2003. The Company recorded $448,000 million of unrealized
loss, net of taxes of $240,000, in other

19

comprehensive loss within shareholders' equity as these hedges were highly
effective. During the third quarter of 2003, the Company reclassified
approximately $2.4 million of losses from other comprehensive loss to oil and
gas production revenues upon settlement of contracts.

Operating Activities. Net cash provided by operating activities was
$57.4 million during the nine months ended September 30, 2003, as compared to
$41.4 million during the first nine months of 2002 due primarily to an increase
in profitability and a $21.5 million increase in depreciation and amortization
resulting from the aforementioned increase in production levels as well as
depreciation on additional DP vessels placed in service. This increase was
partially offset by funding from accounts receivable collections decreasing
$26.1 million as receivables have grown primarily as a result of increased ERT
production levels. Through our ongoing alliance, Horizon Offshore, Inc. provided
11% of the Company's Marine Contracting revenues during the third quarter of
2003.

Investing Activities. Capital expenditures have consisted principally
of strategic asset acquisitions related to the purchase of DP vessels;
construction of the Q4000 and conversion of the Intrepid; acquisition of
Aquatica, Professional Divers, Canyon and Well Ops (U.K.) Limited; improvements
to existing vessels and the acquisition of offshore natural gas and oil
properties.

We incurred $74.0 million of capital expenditures during the first nine
months of 2003 compared to $140.3 million during the comparable prior year
period. Included in the capital expenditures during the first nine months of
2003 was $17.5 million for the purchase of ROV units to support the Canyon MSA
agreement with Technip/Coflexip to provide robotic and trenching services, $26.0
million related to Gunnison development costs, including the spar, as well as
$22.4 million relating to ERT's 2003 well exploitation program. Included in the
$140.3 million of capital expenditures during the first nine months of 2002 was
$25.2 million for the construction of the Q4000 and $31.8 million relating to
the Intrepid DP conversion and Eclipse upgrade.

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

In January 2002, CDI purchased Canyon, a supplier of remotely operated
vehicles (ROVs) and robotics to the offshore construction and telecommunications
industries. CDI purchased Canyon for cash of $52.8 million, the assumption of
$9.0 million of Canyon debt (offset by $3.1 million of cash acquired), 181,000
shares of CDI common stock valued at $4.3 million (143,000 shares of which we
purchased as treasury shares during the fourth quarter of 2001) and a commitment
to purchase the redeemable stock in Canyon at a price to be determined by
Canyon's performance during the years 2002 through 2004 from continuing
employees at a minimum purchase price of $13.53 per share (or $7.5 million). The
Company also agreed to make future payments relating to the tax impact on the
date of redemption, whether employment continued or not. As they are employees,
any share price paid in excess of the $13.53 per share and related tax impact
will be recorded as compensation expense. These remaining shares have been
classified as redeemable stock in subsidiary (long term debt beginning in the
third quarter of 2003 - see Note 3 to consolidated financial statements) in the
accompanying balance sheet and will be adjusted to their estimated redemption
value at each reporting period based on Canyon's performance. In April 2003, the
Company purchased approximately one-third of the redeemable shares at the
minimum purchase price of $13.53 per share. Consideration included approximately
$400,000 of contingent consideration relating to tax gross-up payments paid to
the Canyon employees in accordance with the purchase agreement. This amount was
recorded as goodwill in the period paid (i.e., the second quarter of 2003).

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

20

decommissioning liability. As a result, ERT is the operator with an effective
100% working interest in that field.

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

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

In early 2002, CDI, along with El Paso Energy Partners, formed
Deepwater Gateway L.L.C. (a 50/50 venture) to design, construct, install, own
and operate a tension leg platform ("TLP") production hub primarily for Anadarko
Petroleum Corporation's Marco Polo field discovery in the Deepwater Gulf of
Mexico. Our share of the construction costs is estimated to be approximately
$120 million (approximately $97 million of which had been incurred as of
September 30, 2003). In August 2002, the Company along with El Paso, completed a
non-recourse project financing for this venture, terms of which would include a
minimum equity investment for CDI of approximately $33 million, all of which has
been paid as of September 30, 2003 and is recorded as Investment in Deepwater
Gateway L.L.C. in the accompanying consolidated balance sheet. Terms of the
financing also require CDI to guarantee a balloon payment at the end of the
financing term in 2008 (estimated to be $22.5 million). The Company has not
recorded any liability for this guarantee as management believes it is unlikely
the Company will be required to pay the balloon payment.

In April 2000, ERT acquired a 20% working interest in Gunnison, a
deepwater Gulf of Mexico project of Kerr-McGee Oil & Gas Corporation. Consistent
with CDI's philosophy of avoiding exploratory risk, financing for the
exploratory costs of approximately $20 million was provided by an investment
partnership (OKCD Investments, Ltd.), the investors of which are current or
former CDI senior management, in exchange for an overriding royalty interest of
25% of CDI's 20% working interest. CDI provided no guarantees to the investment
partnership. The Board of Directors established three criteria to determine a
commercial discovery and the commitment of Cal Dive funds: 75 million barrels
(gross) of reserves, 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. With the sanctioning of a commercial discovery, the Company is
funding 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 ($86 million of which had been incurred by September 30, 2003) with over
half of that for construction of the spar. See footnote 10 to the Company's
Consolidated Financial Statements included herein for discussion of financing
relating to the spar construction.

Financing Activities. We have financed seasonal operating requirements
and capital expenditures with internally generated funds, borrowings under
credit facilities, and the sale of equity 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. During the first nine months of 2002, we borrowed
$43.9 million on this facility resulting in an outstanding balance of $142.1
million at December 31, 2002. We have not drawn on this facility in 2003. The
MARAD debt is payable in equal semi-annual installments beginning in August 2002
and maturing 25 years from such date. We made two such payments during the nine
months ending September 30, 2003 totaling $2.8 million. It is collateralized by
the Q4000, with Cal Dive guaranteeing 50% of the debt, and bears an interest
rate which currently floats at a rate approximating AAA Commercial Paper yields
plus 20 basis points (approximately 1.5% as of September 30, 2003). For a period
up to ten years from delivery of the vessel in April 2002, the Company has
options to lock in a fixed rate. In accordance with the MARAD debt agreements,
we are required to comply with certain covenants and restrictions, including the
maintenance of minimum net

21

worth, working capital and debt-to-equity requirements. As of September 30,
2003, we were in compliance with these covenants.

The Company has a $70 million revolving credit facility due in 2005.
This facility is collateralized by accounts receivable and certain of the
Company's Marine Contracting vessels, bears interest at LIBOR plus 125-250 basis
points depending on CDI leverage ratios (approximately 3.4% as of September 30,
2003) and, among other restrictions, includes three financial covenants (cash
flow leverage, minimum interest coverage and fixed charge coverage). As of
September 30, 2003, the Company had drawn $35.9 million (a $16.7 million
reduction from December 31, 2002) under the revolving credit facility and was in
compliance with these covenants.

In November 2001, ERT entered into a five-year lease transaction with
an entity owned by a third party to fund CDI's portion of the construction costs
($67 million) of the spar for the Gunnison field. As of December 31, 2001 and
June 30, 2002, the entity had drawn down $5.6 million and $22.8 million,
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. In August 2002, CDI acquired 100% of the equity of the
entity and converted the notes into a term loan. The total commitment of the
loan was reduced to $35 million and will be payable in quarterly installments of
$1.75 million for three years after delivery of the spar with the remaining
$15.75 million due at the end of the three years. The facility bears interest at
LIBOR plus 225-300 basis points depending on CDI leverage ratios (approximately
3.6% as of September 30, 2003) and includes, among other restrictions, three
financial covenants (cash flow leverage, minimum interest coverage and debt to
total book capitalization). The Company was in compliance with these covenants
as of September 30, 2003. We drew $5.7 million on this facility in the first
nine months of 2003.

On January 8, 2003, CDI completed the private placement of $25 million
of a newly designated class of cumulative convertible preferred stock (Series
A-1 Cumulative Convertible Preferred Stock, par value $0.01 per share) that is
convertible into 833,334 shares of Cal Dive common stock at $30 per share. The
preferred stock was issued to a private investment firm. The preferred stock
holder has the right to purchase as much as $30 million in additional preferred
stock for a period of two years beginning in July 2003. The conversion price of
the additional preferred stock will equal 125% of the then prevailing market
price of Cal Dive common stock, subject to a minimum conversion price of $30 per
common share. The preferred stock has a minimum annual dividend rate of 4%, or
LIBOR plus 150 basis points if greater, payable quarterly in cash or common
shares at Cal Dive's option. CDI paid the first, second and third quarter 2003
dividends on the last day of the respective quarters in cash. After the second
anniversary, the holder may redeem the value of its original investments in the
preferred shares to be settled in common stock at the then prevailing market
price or cash at the discretion of the Company. Under certain conditions, the
holder could redeem its investment prior to the second anniversary. The proceeds
received from the sale of this stock, net of transaction costs, have been
classified outside of shareholders' equity on the balance sheet below total
liabilities. The transaction costs have been deferred, and are being accreted
through the statement of operations over two years. Prior to the conversion,
common shares issuable will be assessed for inclusion in the weighted average
shares outstanding for the Company's diluted earnings per share under the if
converted method based on the Company's common share price at the beginning of
the applicable period.

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

In August 2003, Canyon Offshore, Ltd. (a U.K. subsidiary - "COL") (with
a parent guarantee from Cal Dive) completed a capital lease with Bank of
America, Inc. ("B of A") refinancing the construction costs of a newbuild 750
horsepower trenching unit and a ROV. COL received proceeds of $12 million for
the assets and agreed to pay B of A sixty monthly installment payments of
$217,174 (resulting in an implicit interest rate of 3.29%). COL has an option to
purchase the assets at the end of the lease term for $1. The proceeds were used
to reduce the Company's revolving credit facility, which had initially funded

22

the construction costs of the assets. This transaction will be accounted for as
a capital lease under SFAS No. 13 with the present value of the lease obligation
(and corresponding asset) being reflected on the Company's consolidated balance
sheet during the third quarter of 2003.

During the first nine months of 2003, we made payments of $1.3 million
on capital leases relating to Canyon. The only other financing activity during
the nine months ended September 30, 2003 and 2002 involved the exercise of
employee stock options.

The following table summarizes our contractual cash obligations as of
September 30, 2003 and the scheduled years in which the obligation are
contractually due:

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

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

23

ITEM 3. Quantitative and qualitative disclosure about market risk

The Company is currently exposed to market risk in two major areas:
commodity prices and foreign currency. Because 95% of the Company's debt at
September 30, 2003 was based on floating rates, changes in interest would,
assuming all other things equal, have a minimal impact on the fair market value
of the debt instruments. Assuming September 30, 2003 debt levels, every 100
basis points move in interest rates would result in $2.3 million of annualized
interest expense or savings, as the case may be, to the Company.

Commodity Price Risk

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

As of September 30, 2003, the Company has the following volumes under
derivative contracts related to its oil and gas producing activities:

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

Foreign Currency Exchange Rates

Because we operate in various oil and gas exploration and production
regions in the world, we conduct a portion of our business in currencies other
than the U.S. dollar (primarily with respect to Well Ops (U.K.) Limited). The
functional currency for Well Ops (U.K.) Limited is the applicable local
currency. Although the revenues are denominated in the local currency, the
effects of foreign currency fluctuations are partly mitigated because local
expenses of such foreign operations also generally are denominated in the same
currency. The impact of exchange rate fluctuations during the three months ended
September 30, 2003 did not have a material effect on reported amounts of
revenues or net income.

Assets and liabilities of Well Ops (U.K.) Limited are translated using
the exchange rates in effect at the balance sheet date, resulting in translation
adjustments that are reflected in accumulated other comprehensive income (loss)
in the stockholders' equity section of our balance sheet. Approximately 10% of
our net assets are impacted by changes in foreign currencies in relation to the
U.S. dollar. We recorded a $690,000 adjustment, net of taxes, to our equity
account for the three months ended September 30, 2003 to reflect the net impact
of the decline of the British Pound against the U.S. dollar.

24

Canyon Offshore, the Company's ROV subsidiary, has operations in the
United Kingdom and Southeast Asia sectors. Canyon conducts the majority of its
affairs in these regions in U.S. dollars which it considers the functional
currency. When currencies other than the U.S. dollar are to be paid or received
the resulting gain or loss from translation is recognized in the statements of
operations. These amounts for the three months ended September 30, 2003 were not
material to the Company's results of operations or cash flows.

ITEM 4. CONTROLS AND PROCEDURES

The Company's management, with the participation of the Company's
principal executive officer (CEO) and principal financial officer (CFO),
evaluated the effectiveness of the Company's disclosure controls and procedures
(as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities
Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the
fiscal quarter ended September 30, 2003. Based on this evaluation, the CEO and
CFO have concluded that the Company's disclosure controls and procedures were
effective as of the end of the fiscal quarter ended September 30, 2003 to ensure
that information that is required to be disclosed by the Company in the reports
it files or submits under the Exchange Act is recorded, processed, summarized
and reported, within the time periods specified in the SEC's rules and forms.
There were no changes in the Company's internal control over financial reporting
that occurred during the fiscal quarter ended September 30, 2003 that has
materially affected, or is reasonable likely to materially affect, the Company's
internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item I, Note 11 to Consolidated Financial Statements, which
is incorporated herein by reference.

ITEM 4. Submission of matters to a Vote of Security Holders

The Annual Meeting of Shareholders of Cal Dive was held on May 14,
2003, in Houston, Texas, for the purpose of electing two Class II directors and
approving amendments to the 1998 Employee Stock Purchase Plan. Proxies for the
meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act
of 1934, and there was no solicitation in opposition to management's
solicitations.

(a) Each of the Class II directors nominated by the Board and listed in
the proxy statement was elected with votes as follows:

The term of office of each of the following directors continued after the
meeting:

Gordon F. Ahalt
Bernard Duroc-Danner
Martin Ferron
Owen Kratz
John V. Lovoi
Anthony Tripodo

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(b) The amendments to the 1998 Employee Stock Purchase Plan were
approved by the following vote: 35,402,000 shares for; 290,469
shares against and 172,564 shares abstaining.

Item 5. Other Information

The value realized upon exercise of stock options for A. Wade Pursell
for fiscal year 2002 as reported in the Company's Proxy should have been
$398,625 instead of the $227,125 reported.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits -

Exhibit 10.1 - Lease with Purchase Option Agreement between
Banc of America Leasing & Capital, LLC and Canyon Offshore
Ltd. dated July 31, 2003

Exhibit 15.1 - Independent Accountants' Acknowledgement Letter

Exhibit 31.1 - Certification Pursuant to Rule 13a-14(a) under
the Securities Exchange Act of 1934 by Owen Kratz, Chief
Executive Officer

Exhibit 31.2 - Certification Pursuant to Rule 13a-14(a) under
the Securities Exchange Act of 1934 by A. Wade Pursell, Chief
Financial Officer

Exhibit 32.1 - Section 1350 Certification by Owen Kratz, Chief
Executive Officer

Exhibit 32.2 - Section 1350 Certification by A. Wade Pursell,
Chief Financial Officer

Exhibit 99.1 - Independent Accountants' Review Report

(b) Reports on Form 8-K -

Current Report on Form 8-K filed August 1, 2003 to report the
Company's 2003 second quarter financial results and its
forecast results for the year ending December 31, 2003.

Current Report on Form 8-K filed August 13, 2003 to report a
notice of a blackout period from the Cal Dive International,
Inc. Employee Retirement Savings Plan Investment Committee to
directors and executive officers of the Company.

26

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.

CAL DIVE INTERNATIONAL, INC.

Date: November 12, 2003 By: /s/ Owen Kratz
--------------------------------------
Owen Kratz, Chairman
and Chief Executive Officer

Date: November 12, 2003 By: /s/ Wade Pursell
--------------------------------------
A. Wade Pursell, Senior Vice President
and Chief Financial Officer

27

INDEX TO EXHIBIT

Exhibit 10.1 - Lease with Purchase Option Agreement between
Banc of America Leasing & Capital, LLC and Canyon Offshore
Ltd. dated July 31, 2003

Exhibit 15.1 - Independent Accountants' Acknowledgement Letter

Exhibit 31.1 - Certification Pursuant to Rule 13a-14(a) under
the Securities Exchange Act of 1934 by Owen Kratz, Chief
Executive Officer

Exhibit 31.2 - Certification Pursuant to Rule 13a-14(a) under
the Securities Exchange Act of 1934 by A. Wade Pursell, Chief
Financial Officer

Exhibit 32.1 - Section 1350 Certification by Owen Kratz, Chief
Executive Officer

Exhibit 32.2 - Section 1350 Certification by A. Wade Pursell,
Chief Financial Officer

Exhibit 99.1 - Independent Accountants' Review Report