CAL DIVE INTERNATIONAL INC - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

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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 June 30, 2003

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

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Commission File Number: 0-22739

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

Minnesota 95-3409686
(State or Other Jurisdiction of (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)

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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 August 13, 2003 there were 37,671,788 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 -
June 30, 2003 and December 31, 2002...................................................1

Consolidated Statements of Operations -

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

Six Months Ended June 30, 2003 and June 30, 2002......................................3

Consolidated Statements of Cash Flows -

Six Months Ended June 30, 2003 and
June 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 6. Exhibits and Reports on Form 8-K.................................................25

Signatures..................................................................................26

PART I. FINANCIAL STATEMENTS

Item 1. Financial Statements

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

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)

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)

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) which 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 June 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 six 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 .................. 2,957
Liabilities settled during the period ................. (2,930)
Accretion expense ..................................... 1,760
--------
Asset retirement obligation at June 30, 2003 .......... $ 67,680
========

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.

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

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the controlled entity. FIN No. 46 applies to variable interest entities created
after January 31, 2003, and applies in the first interim period beginning after
June 15, 2003 to variable interest entities created before February 1, 2003. The
Company is currently evaluating the impact the adoption will have on its
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
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
is currently evaluating the impact the adoption of SFAS No. 150 will have on its
consolidated financial statements.

Note 4 - Comprehensive Income

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

The components of accumulated other comprehensive loss as of June 30,
2003 are as follows (in thousands):

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.

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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 six 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 $6.8 million as
of June 30, 2003. The Company recorded $4.4 million of unrealized loss, net of
taxes of $2.4 million, in other comprehensive loss within shareholders' equity
as these hedges were highly effective. During the second quarter of 2003, the
Company reclassified approximately $3.2 million of losses from other
comprehensive loss to oil and gas production revenues upon settlement of such
contracts.

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

8

In July 2003, the Company entered into additional swap contracts to
hedge oil production of 15 MBbls per month for January through June 2004 at
$26.90 per barrel and 20 MBbls per month for July through August 2004 at $26.00
per barrel.

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
gain of $2.2 million, net of taxes of $1.2 million, in the second quarter of
2003 is included as accumulated other comprehensive 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 June 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 June 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 month and six months ended June 30, 2003 and 80,000 and 200,000 shares for
the three months and six months ended June 30, 2002, respectively, were not
dilutive and, therefore, were not included in the computations of diluted income
per common share amounts. In addition, approximately 1.4 million and 1.1 million
shares attributable to the convertible preferred stock were excluded from the
three months and six months ended June 30, 2003, calculation of diluted EPS,
respectively, 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):

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 in 2003 and 2002 was $12.63 and $15.42,
respectively. The estimated fair value of the options is amortized to pro forma
expense over the vesting period.

10

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 quarter ended June 30, 2003 the Company derived $16.2
million of its revenues from the U.K. sector utilizing $111.6 million of its
total assets in this region. Additionally, $22.8 million and $17.5 million of
revenues were derived from the Latin America sector during the three months
ended June 30, 2003 and 2002, respectively. The majority of the remaining
revenues were generated in the U.S. Gulf of Mexico.

Note 10 - Long-Term Financings

In August 2000, the Company closed a $138.5 million long-term financing
for construction of the Q4000. This U.S. Government guaranteed financing is
pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by
the Maritime Administration ("MARAD Debt"). In January 2002, the Maritime
Administration agreed to expand the facility to $160 million to include the
modifications to the vessel which had been approved during 2001. The MARAD Debt
is payable in equal semi-annual installments beginning in August 2002 and
maturing 25 years from such date. It is collateralized by the Q4000, with CDI
guaranteeing 50% of the debt, and bears interest at a rate which currently
floats at a rate approximating AAA Commercial Paper yields plus 20 basis points
(approximately 1.5% as of June 30, 2003). For a period up to ten 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, working capital and debt-to-equity requirements. As of June 30, 2003, the
Company was in compliance with these covenants.

The Company has a revolving credit facility which was increased from
$40 million to $70 million during 2002 and the term extended for three years.
This facility is collateralized by accounts receivable and certain of the
remaining vessel fleet, bears interest at LIBOR plus 125-250 basis points
depending on CDI leverage ratios (approximately 3.8% as of June 30, 2003) and,
among other restrictions, includes three financial covenants (cash flow
leverage, minimum interest coverage and fixed charge coverage). As of June 30,
2003, the Company had drawn $46.4 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

11

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 4.0% as of June 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 June 30, 2003. As of June 30, 2003 the
Company has drawn down $33.0 million on the facility.

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

During the three months ended June 30, 2003 and 2002, the Company made
no cash payments for interest charges, net of capitalized interest. The Company
capitalized interest totaling $1.9 million and $2.2 million during the six
months ended June 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 engaged in a large
construction project, and in late September, 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 ($11.9 million of
which had not been collected as of June 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 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 had responded alleging EEX
Corporation breached various provisions of the same contracts. EEX's acquisition
by Newfield during the fourth quarter 2002 enabled CDI to enter meaningful
settlement discussions prior to the trial date, which was set for February 2003.
This resulted in a settlement including CDI making a cash payment, during the
first quarter of 2003, and agreeing to provide work credits for its services
over the next three years. The total value of the settlement was recorded in the
Company's statement of operations for the year ended December 31, 2002. This
settlement combined with the reserves on the project discussed above

12

resulted in approximately $10 million of pre-tax charges recorded in the
statement of operations in the fourth quarter of 2002.

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 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).

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

13

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.
CDI paid the first and second 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 fully diluted earnings per
share using the if converted method based on the Company's common share price at
the beginning of the applicable period.

During the first quarter of 2003, the Company filed a registration
statement registering approximately 7.5 million shares of common stock relating
to this transaction, the maximum potential total number shares of common stock
redeemable under certain circumstances, subject to the Company's ability to
redeem with cash, under the terms of the agreement. The registration statement
became effective April 30, 2003.

Note 15 - Subsequent Event - Canyon Refinancing

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
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.

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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.

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, plant 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.

15

RESULTS OF OPERATIONS

Comparison of Three Months Ended June 30, 2003 and 2002

Revenues. During the three months ended June 30, 2003, the Company's
revenues increased 41% to $101.8 million compared to $72.3 million for the three
months ended June 30, 2002. Of the overall $29.5 million increase, $20.2 million
was generated by the Oil and Gas Production segment due to higher oil and gas
prices and increased production. The balance of the increase was due primarily
to the addition of the MSV Seawell and related Well Ops (U.K.) Limited business
unit in July 2002 ($13.3 million). Lower utilization of the 11 vessels dedicated
to the Outer Continental Shelf ("OCS") (55% for the three months ended June 30,
2003 versus 66% in the year ago quarter) resulted in a 21% decline in revenues
contributed by these vessels.

Oil and Gas Production revenue for the three months ended June 30, 2003
increased $20.2 million, or 160%, to $32.9 million from $12.6 million during the
comparable prior year period. The average realized natural gas price of $5.02
per Mcf, net of hedges in place, during the second quarter of 2003 was 50%
higher than the $3.34 per Mcf realized in the comparable prior year quarter.
Increasing oil prices had less of an impact on revenues as they increased only
6% to $26.64 per barrel, net of hedges in place, during the three months ended
June 30, 2003 from $25.11 per barrel in the comparable prior year quarter. The
91% increase in production (6.7 Bcfe for the three months ended June 30, 2003
compared to 3.5 Bcfe in the second quarter of 2002) is a result of the four
significant property acquisitions completed last year.

Gross Profit. Gross profit of $24.2 million for the second quarter of
2003 represents a 41% increase compared to the $17.2 million recorded in the
comparable prior year period with the Oil and Gas Production segment
contributing all of the increase. Marine Contracting gross profit declined $1.4
million, or 13%, to $9.4 million for the three months ended June 30, 2003, from
$10.8 million in the prior year period. While the addition of the Seawell added
$2.3 million of gross profit for the second quarter of 2003, the Q4000 worked at
lower rates resulting in a decrease in gross profit of $2.0 million as compared
to the comparable prior year quarter. Lower utilization and a more competitive
market on the OCS, including one of our four-point vessels remaining stacked
throughout the second quarter of 2003, further contributed to the decline in
gross profit. Offsetting these declines was an $8.4 million, or 132%, increase
in Oil and Gas Production gross profit due to the increases in the average
realized commodity prices and production noted above.

Gross margins of 24% in the second quarter of 2003 were identical to
the prior year period. Marine Contracting margins dropped 4 points to 14% for
the three months ended June 30, 2003 from 18% in the comparable prior year
quarter due to the factors noted above. In addition, margins in the Oil and Gas
Production segment declined 5 points to 45% for the three months ended June 30,
2003 from 50% in the year ago quarter due to a high level of expensed well work
and a decline in oil production at the end of June 2003 due to a problem with a
major trunkline owned by a third party.

Selling & Administrative Expenses. Selling and administrative expenses
of $8.6 million for the three months ended June 30, 2003 are $2.4 million higher
than the $6.2 million incurred in the second quarter of 2002 due primarily to
the business units acquired and higher insurance premiums. Overhead at 9% of
revenues for the current quarter held steady as compared to the comparable prior
year period.

Other (Income) Expense. The Company reported other expense of $1.1
million for the three months ended June 30, 2003 compared to other income of
$105,000 for the three months ended June 30, 2002. The difference between
periods is due primarily to the $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 $824,000 in the second
quarter

16

of 2003 is slightly higher than the $775,000 incurred in the three months ended
June 30, 2002 due to higher debt levels.

Income Taxes. Income taxes increased to $5.2 million for the three
months ended June 30, 2003 compared to $3.9 million in the comparable prior year
period due to increased profitability. The effective rate increased to 36% in
the second 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 June
30, 2003 was $1.7 million greater than the comparable period in 2002 as a result
of factors described above.

Comparison of Six Months Ended June 30, 2003 and 2002

Revenues. During the six months ended June 30, 2003, revenues increased
$64.5 million, or 51%, to $190.7 million compared to $126.2 million for the six
months ended June 30, 2002. The Marine Contracting segment contributed $19.2
million of the increase, primarily the result of the acquisition of the Seawell
($17.0 million) as well as a full six months of work for the Q4000 and the
Intrepid in 2003 as compared to three 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 six months ended June 30, 2003
increased $45.3 million, or 204%, to $67.5 million from $22.2 million during the
comparable prior year period. The increase was due to a 50% increase in our
average realized commodity prices to $4.93 per Mcfe, net of hedges in place
($5.14 per Mcf of natural gas and $27.69 per barrel of oil) in the first half of
2003 from $3.28 per Mcfe ($2.99 per Mcf of natural gas and $22.74 per barrel of
oil) in the six months ended June 30, 2002. Production more than doubled to 13.5
Bcfe during the first half of 2003 from 6.4 Bcfe during the comparable prior
year period as a result of the property acquisitions during 2002.

Gross Profit. Gross profit of $43.4 million for the first half of 2003
was $15.1 million, or 53%, greater than the $28.3 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 $23.2 million from $10.8 million in the first half of 2002 to $34.0
million for the six months ended June 30, 2003, due to the increases in average
realized commodity prices and production described above. Offsetting this
increase was a 46% decrease in the Marine Contracting segment gross profit to
$9.4 million for the six months ended June 30, 2003 from $17.5 million in the
comparable prior year period. This decline is primarily due to a loss of
$620,000 on the Q4000 in 2003 as compared to $2.2 million in gross profit for
the first half of 2002. Canyon gross profit also declined by $3.1 million due to
the decline in telecom cable burial work.

Gross margins remained relatively flat at 23% for the six months ended
June 30, 2003 and June 30, 2002. Marine Contracting margins decreased from 17%
for the first half of 2002 to 8% during the first half of 2003 due mainly to the
depressed markets for offshore construction in the GOM and the North Sea and
increased competition in the OCS market. Oil and Gas Production gross margins
increased slightly to 50% for the six months ended June 30, 2003 from 49% for
the first half of 2002 due to the aforementioned increases in average realized
commodity prices.

Selling & Administrative Expenses. Selling and administrative expenses
were $17.6 million in the first half of 2003, which is 41% more than the $12.5
million incurred in the first half of 2002, primarily due to the addition of
business units acquired and higher insurance premiums. We added one point to
operating margins as overhead expenses decreased to 9% of revenues in the first
half of 2003 as compared to 10% of revenues in the comparable prior year period.

17

Other (Income) Expense. The Company reported other expense of $2.2
million for the six months ended June 30, 2003 in contrast to $91,000 for the
six months ended June 30, 2002. Included in other expense for the first half of
2002 is the $1.1 million gain on our foreign currency derivative, as discussed
above. Net interest expense of $1.5 million for the first half of 2003 is higher
than the $800,000 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 quarter of the 2002 period.

Income Taxes. Income taxes increased to $8.5 million for the six months
ended June 30, 2003, compared to $5.5 million in the comparable prior year
period due to increased profitability. The effective rate increased to 36% in
the first half of 2003 compared to 35% in 2002 due to provisions for foreign
taxes.

Net Income. Net income of $15.0 million for the six months ended June
30, 2003 was $4.7 million, or 46%, 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. 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 June 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
June 30, 2003 our debt to total book capitalization had declined to 37% and
working capital had increased to $26.1 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 primarily related 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.

19

During the second half of 2002 and first half 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 $6.8 million as of
June 30, 2003. The Company recorded $4.4 million of unrealized loss, net of
taxes of $2.4 million, in other comprehensive loss within shareholders' equity
as these hedges were highly effective. During the second quarter of 2003, the
Company reclassified approximately $3.2 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
$24.3 million during the six months ended June 30, 2003, as compared to $30.8
million during the first six months of 2002. This decrease was primarily due to
a $23.4 million decrease in funding from accounts payable and accrued
liabilities due primarily to payments made for Gunnison development as well as
the completion of several ERT well work programs in the first half of 2003. In
addition, several vessels were under construction or in drydock at June 30, 2002
resulting in higher accruals. Funding from accounts receivable collections
decreased $6.4 million as receivables have grown primarily as a result of
increased ERT production levels. Offsetting these declines are an increase in
profitability and a $16.7 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.

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 $42.3 million of capital expenditures during the first six
months of 2003 compared to $91.2 million during the comparable prior year
period. Included in the capital expenditures during the first six months of 2003
was $13.8 million for the Canyon MSA (agreement with Technip/Coflexip to provide
robotic and trenching services), $12.4 million related to Gunnison development
costs, including the spar, as well as $9.1 million relating to ERT's 2003 well
exploitation program. Included in the $91.2 million of capital expenditures
during the first half of 2002 was $36.5 million for the construction of the
Q4000 and $20.3 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 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

20

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).

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
$110 million (approximately $86 million of which had been incurred as of June
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 June 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 ($76 million of which had been incurred by June 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, 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 2001 and 2002, we borrowed $59.5 million and $43.9 million
($38.9 of which was in the first half of 2002), respectively, 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 one such payment in the first quarter of 2003 for $1.4
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
approximately AAA Commercial Paper yields plus 20 basis points (approximately
1.5% as of June 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,

21

including the maintenance of minimum net worth, working capital and
debt-to-equity requirements. As of June 30, 2003, we were in compliance with
these covenants.

The Company has a revolving credit facility which was increased from
$40 million to $70 million during 2002 and the term extended for 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 (approximately 3.8% as of June 30, 2003) and, among other
restrictions, includes three financial covenants (cash flow leverage, minimum
interest coverage and fixed charge coverage). As of June 30, 2003, the Company
had drawn $46.4 million (a $6.2 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
4.0% as of June 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 June 30, 2003. We drew $3.8 million on this facility in the first half 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 and second 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 fully diluted earnings per share under the
if converted method based on the Company's common share price at the beginning
of the applicable period. During the first quarter of 2003, the Company filed a
registration statement registering approximately 7.5 million shares of common
stock relating to this transaction, the maximum potential total number shares of
common stock redeemable under certain circumstances, subject to the Company's
ability to redeem with cash, under the terms of the agreement. The registration
statement became effective April 30, 2003.

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

22

approximately $87.2 million were used for the Well Ops (U.K.) Limited
acquisition, ERT acquisitions and to retire dept under the Company's revolving
line of credit.

During the first six months of 2003, we made payments of $740,000 on
capital leases assumed in the Canyon acquisition. The only other financing
activity during the six months ended June 30, 2003 and 2002 involved the
exercise of employee stock options.

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
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.

The following table summarizes our contractual cash obligations as of
June 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 all of the Company's debt at June
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 June 30, 2003 debt levels, every 100 basis points move in
interest rates would result in $2.2 million of annualized interest expense or
savings, as the case may be, to the Company.

Commodity Price Risk

The Company has utilized derivative financial instruments with respect
to a portion of 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 June 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
June 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 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 $2.2 million adjustment, net of taxes, to our equity
account for the three months ended June 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 June 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 June 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 June 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 June 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 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits -

Exhibit 15.1 - Independent Accountants' Acknowledgment 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 May 2, 2003 to report the
Company's 2003 first quarter financial results and its
forecast results for the quarter ending June 30, 2003.

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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: August 14, 2003 By: /s/ Owen Kratz
--------------------------------------
Owen Kratz, Chairman
and Chief Executive Officer

Date: August 14, 2003 By: /s/ Wade Pursell
--------------------------------------
A. Wade Pursell, Senior Vice President
and Chief Financial Officer

26

INDEX TO EXHIBITS