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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NO. 0-22739
CAL DIVE INTERNATIONAL, INC.
(Exact name of registrant as specified in its charter)
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MINNESOTA 95-3409686
(State or other jurisdiction of (I.R.S. Employer
incorporation of organization) Identification No.)
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400 N. SAM HOUSTON PARKWAY E., 77060
SUITE 400 (Zip Code)
HOUSTON, TEXAS
(Address of Principal Executive Offices)
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Registrant's telephone number, including area code: (281) 618-0400
Securities registered pursuant to Section 12(b) of the Act:
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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None None
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Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK (NO PAR VALUE)
(TITLE OF CLASS)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the voting stock held by non-affiliates of
the registrant as of March 24, 2000 was $341,003,415 based on the last reported
sales price of the Common Stock on March 24, 2000, as reported on the
NASDAQ/National Market System.
The number of shares of the registrant's Common Stock outstanding as of
March 24, 2000 was 15,664,658.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement for the Annual Meeting of
Shareholders to be held on May 10, 2000 are incorporated by reference into Part
III hereof.
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CAL DIVE INTERNATIONAL, INC. ("CDI") INDEX -- FORM 10-K
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PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 13
Item 3. Legal Proceedings........................................... 16
Item 4. Submission of Matters to a Vote of Security Holders......... 16
Unnumbered
Item Executive Officers of Registrant............................ 16
PART II
Item 5. Market for the Registrant's Common Equity and Related
Shareholder Matters......................................... 18
Item 6. Selected Financial Data..................................... 19
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 20
Results of Operations....................................... 22
Liquidity and Capital Resources............................. 23
Item 7A Quantitative and Qualitative Disclosure About Market Risk... 26
Item 8. Financial Statements and Supplementary Data................. 27
Independent Auditors' Report................................ 28
Consolidated Balance Sheets -- December 31, 1999 and 1998... 29
Consolidated Statements of Operations -- Three Years Ended
December 31, 1999........................................... 30
Consolidated Statements of Shareholders' Equity -- Three
Years Ended December 31, 1999............................... 31
Consolidated Statements of Cash Flows -- Three Years Ended
December 31, 1999........................................... 32
Notes to Consolidated Financial Statements.................. 33
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure.................................... 46
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 46
Item 11. Executive Compensation...................................... 46
Item 12. Security Ownership of Certain Beneficial Owners and
Managers.................................................... 46
Item 13. Certain Relationships and Related Transactions.............. 46
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 47
Signatures.................................................. 49
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PART I
ITEM 1. BUSINESS.
Summary
Cal Dive International, Inc., together with its subsidiaries, is a leading
subsea development contractor providing services from the shallowest to the
deepest waters in the Gulf of Mexico. Over three decades, we have earned a
reputation for innovation both in partnering with our customers and in
underwater construction techniques and equipment. With a diversified fleet of 15
vessels, along with barges available under an alliance, our work covers the life
of an offshore natural gas or oil field. Through one of our subsidiaries, Energy
Resource Technology, Inc. ("ERT"), we acquire mature offshore properties to
provide a cost effective alternative to the decommissioning process. Our
customers include major and independent natural gas and oil producers, pipeline
transmission companies and offshore engineering and construction firms.
In Gulf water depths greater than 1,000 feet, we are a leader in solving
technological challenges encountered in the "Deepwater". Many of our Deepwater
projects from 1999 forward will involve use of unique techniques or technologies
we have developed (including the patent on the design of our new vessel Q4000).
With a fleet of six Deepwater-capable vessels, we have a technically diverse
fleet for the delivery of these subsea solutions. We have also formed alliances
with other offshore service and equipment providers and customers which enhance
our ability to provide full field and life of field services.
In shallow water depths up to 1,000 feet, we are a dominant provider of
services which include air and SAT diving. Fourteen of our vessels perform these
services, five of which support SAT diving. In 1999, we doubled the size and
management strength of our shallow dive operations by purchasing the shares of
Aquatica we did not already own. We also completed five projects involving
shallow water full-field development/pipelay bringing new wells online at low
cost and in a short period of time (as little as 17 weeks).
We are a leader in the operation and decommissioning of mature oil and gas
properties in the shallow water Gulf of Mexico. Our salvage assets set an
all-time revenue record in 1999 despite a weak market. Through our subsidiary
ERT, we are one of few companies with the combined attributes of financial
strength, reservoir engineering, operations expertise and company-owned salvage
assets that is acquiring and operating mature properties in the Gulf of Mexico.
In 1999, ERT doubled its properties and increased production levels 82% over
1998.
Overview of 1999 Developments
1999 began with our customer base frozen by low commodity prices and
mega-merger activity. As commodity prices improved, however, indicators of
construction activity (including the mobile rig count) remained flat as did
offshore completion and construction work. Rather than going head-to-head with
competitors in the Gulf market, our strategy shifted to focus on four unique
actions: (i) negotiating large contracts where we functioned as general
contractor (see "General Contractor Projects" below); (ii) completing projects
in our new business unit using a modular package for fast-track full-field
development (see "Shallow Full-Field Development" below); (iii) doubling the
size of ERT by purchasing new offshore blocks (see "ERT Growth" below); and (iv)
purchasing the Cal Dive Aker Dove under favorable terms (see "Deepwater Vessels"
below). As a result, we were able to achieve substantially all of our below
stated 1999 goals:
- a return on invested capital of over 12%;
- double ERT revenues;
- combined Salvage revenues (including ERT and barge operations) equal to
30% of total revenues;
- expand our role as a general contractor;
- utilize the DP fleet to solve Deepwater problems; and
- commence construction of the Q4000.
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Overall, we earned business with our specialized fleet, ability to manage
complex projects and our unique structure. We also closed 1999 with over $20
million cash on hand and no debt. Our clean balance sheet and strong performance
suggests that we have weathered the storm of volatile commodity prices better
than most. While difficult to forecast, we believe we are well positioned for
the recovery that downturns such as 1998/1999 have produced in the past.
General Contractor Projects
Examples of large negotiated general contractor projects in 1999 include:
- In March of 1999, we were awarded a shallow water salvage contract (the
largest such contract in our history) to decommission Sabine Pass No. 9
involving removal of nine (9) structures with 24 wells and 30 pipelines.
This complex work involved not only our barge and vessel assets but also
project management of equipment from a number of alliance partners.
- During the summer of 1999, the MSV Uncle John established a deepwater
record for a subsea construction vessel at Exxon's high profile Diana
field. We installed two 50-ton suction piles, a 70 and 92-ton manifold
and five subsea trees in 4,800 feet of water. We believe this is the
first time a vessel other than a drilling rig has ever completed such
tasks. All of the items were lowered to the seabed on a drillstring from
the derrick on the Uncle John, while two Triton XL ROV systems handled
positioning. The project saved Exxon an estimated 20% from the drill rig
rates of the third quarter. A unique aspect of the project involved a
material barge positioning the 92-ton manifold beneath the Uncle John,
with the vessel then lifting the manifold on its derrick before lowering
to the ocean floor. This unique approach will be an integral feature of
the Q4000.
- During the third and fourth quarter of 1999, we undertook the Cooper
field abandonment, the first ever Deepwater subsea decommissioning
project in the Gulf of Mexico. We removed a large freestanding production
riser, a 12-point mooring system, the floating production unit and a
variety of subsea equipment. Three of our vessels, the Uncle John, Witch
Queen and Dove, performed a number of complex operations including
solving unanticipated downhole conditions such as paraffin blockages and
hydrates. Technical aspects of the project, the largest ever undertaken
by Cal Dive, were featured in Offshore magazine.
Full-Field Development
In 1999, we launched our new full field development product line to assist
cash constrained customers on the Outer Continental Shelf. With 4,000 platforms
and production facilities already in place in the Gulf, our underlying premise
is that each new field need not be re-engineered. Adapting industry standard
designs we now stock subsea trees, prefabricated modules, well panels and
controls and umbilicals for immediate assembly. In 1999, we completed five full
field/pipelay projects including installations for Soco, now Santa Fe Snyder,
Tana Oil and Gas, and ATP.
The development for SOCO was a comprehensive contracting effort which
included the stocked subsea mudline tree and controls from FMC. The time elapsed
between contract signature and commissioning of the well, flowlines and controls
system was one hundred and two days. The Tana Oil and Gas project was an
installation of a 60inches x 48inches caisson/well protector. The caisson was
braced after being driven to grade by 42inches pile and topped off with the
35feet x 40feet deck and heliport from our pre-engineered deck package. On the
ATP Oil and Gas project, we subcontracted to our alliance partner, Horizon
Offshore, for the winter installation of our second deck facility package.
ERT Growth
In 1999, the collapse of commodity prices allowed us to quickly increase
ERT's mature property base by acquiring 20 offshore blocks and tripling the
number of operated wells. We then implemented a well exploitation program which
included the acquisition of 3D seismic and five rig recompletions. As a result,
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monthly production increased to almost one BCF equivalent during the fourth
quarter, an increase of 82% over the first half of 1999 and a level three times
that of the same period in 1998.
The following ERT operating policies were also utilized during 1999 -- we
will sell ERT assets (offshore leases, platforms, compressors, etc.) when the
expected future revenue stream can be accelerated in a single transaction, and;
ERT is not in the exploration business. When 3D seismic identified a prospect
which was successfully drilled by Hall-Houston, they proposed drilling a second
well. ERT instead negotiated a sale of its interest in the two blocks involved.
New Deepwater Vessels
Two developments relating to assets which are part of our Deepwater
strategy occurred in 1999. First, we waited for weak industry conditions to
create an opportunity to acquire a Deepwater vessel in a distressed financial
situation. We moved quickly to acquire an interest in the Cal Dive Aker Dove, a
transaction which took a total of three weeks to identify and close. The Dove
gives us earlier access to capabilities planned with the converted Sea Sorceress
and at a lower price, while moving us further upstream into the high technology
applications of pre-set moorings and suction pile anchoring. We also commenced
construction of our Q4000, our sixth generation, semi-submersible multi-service
vessel which we believe will greatly improve the economics of Deepwater
completion and construction operations. The $150 million vessel is expected to
be christened in mid-2001, in time for the next round of Deepwater construction
activities.
DESCRIPTION OF OPERATIONS
The Industry and CDI
The subsea services industry in the Gulf of Mexico originated in the early
1960s to assist natural gas and oil companies with offshore operations. The
industry has grown significantly since the early 1970s as the domestic oil and
gas industry has increasingly relied upon offshore fields for new production.
Subsea services are required throughout the economic life of an offshore field
and include the following services, among others:
- Exploration. Pre-installation survey; rig positioning and installation
assistance; drilling inspection; subsea equipment maintenance; well
completion; search and recovery operations.
- Development. Installation of production platforms; installation of subsea
production systems; pipelay support including connecting pipelines to
risers and subsea assemblies; pipeline stabilization, testing and
inspection; cable and umbilical lay and connection.
- Production. Inspection, maintenance and repair of production structures,
risers and pipelines and subsea equipment; well intervention; life of
field support.
- Decommissioning. Decommissioning and remediation services; plugging and
abandonment services; platform salvage and removal; pipeline abandonment;
site inspections.
Defined below are certain terms and business concepts helpful to
understanding the services CDI performs in support of offshore development:
Dive Support Vessel (DSV): Specially equipped vessel which performs
services and acts as an operational base for divers, ROVs and specialized
equipment.
Dynamic positioning (DP): Computer-directed thruster systems that use
satellite-based positioning combined with other positioning technologies to
ensure the proper counteraction to wind, current and wave forces enabling
the vessel to maintain its position without the use of anchors. Two DP
systems are required to provide the redundancy necessary to support safe
deployment of divers where only a single DP system is necessary to support
ROV operations.
Moonpool: An opening in the center of a vessel through which a SAT
diving system or ROV may be deployed, allowing the safest diver or ROV
deployment in adverse weather conditions.
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Remotely Operated Vehicle (ROV): Robotic vehicles used to complement,
support and increase the efficiency of diving and subsea operations and for
tasks beyond the capability of manned diving operations.
Saturation (SAT) Diving: SAT diving, required for work in water depths
greater than 300 feet, involves divers working from special chambers for
extended periods at a pressure equivalent to the depth of the work site.
Spot Market: Market prevalent in to the Gulf of Mexico characterized
by projects generally short in duration and often of a turnkey nature.
These projects often require constant rescheduling and the availability or
interchangeability of multiple vessels.
Subsea Construction Vessels. Subsea services are typically performed
with the use of specialized construction vessels which provide an above
water platform that functions as an operational base for divers in water
depths up to 1,000 feet and ROVs at all water depths. Distinguishing
characteristics of subsea construction vessels include DP systems, SAT
diving capabilities, deck space, deck load, craneage and moonpool
launching. Deck space, deck load and craneage are important features of the
vessel's ability to transport and fabricate hardware, supplies and
equipment necessary to complete subsea projects.
Production Contracting. Producers may desire to have a development
contractor involved as a working interest partner in a project to assure
that the contractor/producer interests are truly collaborative. A
production participation deal can be the enabler for securing contracting
work.
Full-Field Development. Subsea contractors offer oil and gas companies
a range of services from subcontracting to complete field development
solutions. We are able to provide a broad range of subsea systems and
services, from procurement and installation of flowlines, wellheads,
control systems, umbilicals and manifolds to installation and commissioning
of the complete production system. Many oil and gas companies prefer to
contract with a consortium capable of undertaking major portions or all of
an entire field development project. Full field development services can
relieve a customer of a substantial amount of the burdens of management of
field development.
Deepwater Technologies
In 1994, we began to assemble a fleet of DP vessels which are required to
deliver subsea services in the Deepwater. Our Deepwater fleet now consists of
one semisubmersible DP MSV (the Uncle John), four DP DSV's (the Witch Queen, the
Balmoral Sea, the Merlin and the Cal Dive Aker Dove), one Deepwater service
barge (the Sea Sorceress), two 4-point moored saturation DSVs (the Cal Diver, I
and the Cal Diver II) and one work class ROV. In 1999, we also commenced
construction of our six-generation DP MSV the Q4000.
Most vessels currently working the Deepwater Gulf (competitors and ours)
were designed in the 1970's for work to a maximum depth of approximately 1,000
fsw. Many of these assets have been modified to apply new technologies out to
4,000 fsw. We designed the Q4000 as a best in class solution to 4000 feet with
unique further capabilities specifically designed to work at 10,000 feet. Its
multi-purpose design allows it to be considered as an alternative to the
drilling rig at that point when it transitions to become a completion support
vessel (i.e. the 30 to 45 days it typically takes to work on setting the tree,
connecting flow lines and testing the well). The vessel is ideally suited to the
long term life of field work that is required including well intervention. We
have applied for patents covering over 50 specific aspects of the vessel,
including the 52-meter three-faced derrick, the underslung cartridge for
pipelay, and a hull structure that does not require cross-bracing.
In 1999, our traditional customer base was not very active. Our 1999
strategy resulted in the expansion of small subcontract positions into two major
projects, at the Diana and Cooper fields, both of which were
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highlighted in the technology section of Offshore magazine and are described in
"Overview of 1999 Developments". Other significant Deepwater projects included:
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DEPTH
FIELD CUSTOMER DESCRIPTION (FSW)
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Diana................... Exxon Mobil Deepest installation work by 4,700
non-drilling rig
Mars.................... Shell Installation of expansion joints 3,000
Cooper.................. EEX First ever decommissioning of GOM 2,200
Deepwater field
Typhoon................. Chevron Geotechnical coring 2,100
Troika.................. BP/Amoco Establish flange connection on rigid 1,800
jumpers
Baldpate................ Amerada Hess Tie-in production from Penn State field 1,650
Pompano................. Exxon Mobil Pig J tube and pull test umbilical 1,300
Gyrfalcon............... Shell Tie-in production from the deployment 1,000
of 15,000 psi subsea tree
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Our Business Development Group, formed in 1996 to cover the emerging
Deepwater market, was recently expanded to include life of field services such
as well intervention and production contracting. This Group coordinates our
efforts with alliance partners as described below:
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ALLIANCE DESCRIPTION
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Schlumberger, Ltd........................ Alliance Agreement whereby we provide DP
vessels and related operating services
for well servicing and testing
Fugro-McClelland Marine Geoscience, Performance Contract whereby we provide
Inc. .................................. vessels for geoscience services and
coring work
TOPS..................................... Preferred Provider Agreement whereby we
provide subsea marine contracting
services in a full field development
setting to TOPS in the Deepwater Gulf of
Mexico
Canyon................................... Alliance Agreement where Canyon supports
our ROV operations and provides ROV
personnel/equipment
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We are also involved in a number of efforts to solve technical challenges
of projects in the Deepwater. For example, a number of wells were lost in 1998
and 1999 to shallow sand flow, a geological phenomenon unique to the Deepwater
Gulf. We are working with an oil company in the development of a newly designed
hammer to drive a caisson 2,000 feet into the ocean floor in order to solve flow
problems. We are also cooperating with a technology group to develop deepwater
tooling and connectors. In each case our goal is to promote development of new
Deepwater products which can be deployed from our fleet of DP vessels.
Traditional Subsea Services
Subsea services performed in shallow waters involve air and saturation
(SAT) diving in support of marine construction activities. We believe that we
are the largest provider of SAT diving services and operate the largest fleet of
SAT diving vessels permanently deployed in the Gulf. All of our SAT diving
vessels have moonpool systems. The services provided by our vessels both overlap
and are complementary in a number of market segments, enabling us to deploy our
vessels to areas of highest utility and margin potential. In 1999, we launched
our new full-field development product line to assist cash-constrained customers
on the OCS described in "Overview of 1999 Developments". It was a tough year,
however, in this part of our business. The revenues of our vessels that work the
OCS were down 26% while those of Aquatica were off 22%. Our dominant presence,
however, allowed us to maintain profit margins at a respectable 37%.
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The industry lost a significant number of experienced subsea people in 1999
due to the downturn. We do not believe people will be a constraint upon our
growth. Our offshore hands and those working at our Operations Base in Morgan
City realized 90% of what they earned in 1998, a record year for our direct
labor. Among other things,this is due to over $2 million of salvage and repair
work our Subsea Services group performed for ERT, most of that coming in the
particularly slow first half of 1999.
In August of 1999 we acquired the 55% of Aquatica, Inc. we did not already
own. Aquatica was created in 1997 to take advantage of a void that opened in the
shallow water market (from the beach to 300 fsw). Sonny Freeman, formerly the
Chief Operating Officer of American Oilfield Divers, has attracted a management
team which has developed a reputation for customer service far beyond that
normally rendered in this market segment. We have now concentrated all shallow
water assets under Aquatica management. Aquatica's fleet currently includes four
DSV's (the Cal Diver III and Mr. Jim, Mr. Joe and Mr. Jack) with delivery of a
fifth DSV (the Cal Diver IV) expected during 2000.
Salvage Services
Since 1997, we have established a leading position in the decommissioning
of facilities in the shallow water of the Gulf of Mexico. According to Offshore
magazine, we performed 24% of all structure removal projects in the Gulf from
January 1, 1996 through June 30, 1998. In 1999, our salvage assets set a new all
time revenue record even though the market was flat compared to the prior year.
The largest Deepwater and OCS decommissioning projects in our history were also
completed in 1999. In addition to the Cooper and Sonat field projects described
in "Overview of 1999 Developments", we were also awarded a Chevron package of
small structure removals (20 caissons and two platforms) and undertook salvage
projects for Samedan, Murphy Oil, Chocktaw Oil and Gas, and Forcenergy. The
subcontracting of Horizon Offshore derrick and pipelay barges to support the
decommissioning of large structures and shallow full-field projects added $10
million to 1999 revenues from this alliance and new product line.
We formed ERT in 1992 to exploit a market opportunity to provide a more
efficient solution to offshore abandonment, to expand our off-season salvage and
decommissioning activity and to support full-field production development
projects. We have assembled and expanded its team of personnel experienced in
geology, geophysics, reservoir, drilling, production engineering, facilities
management and lease operations to allow ERT to better meet each of these goals.
ERT makes its money in three ways: lower salvage costs using our assets,
operating the field more cost effectively, and extending reservoir life through
well exploitation operations. The collapse of commodity prices early in 1999
took many of the small companies which buy mature properties out of the market.
The financial difficulties that these companies experienced also reminded the
majors and large independents that they must again assume responsibility when
buyers having little salvage experience are not able to perform the abandonment
obligation. As a result, ERT was able to double the number of operated
properties (and triple the number of wells operated) early in 1999. We then
conducted a successful well exploitation program which increased 1999 production
by 4 BCFe, or 82% over 1998 levels. In addition, three of the properties
acquired are oilfields which took oil and condensate production to 40% of ERT
fourth quarter revenues, up from our historical average of 10%.
For certain financial information related to each of our business segments,
including revenues, income from operations and total assets, see Notes to
Consolidated Financial Statements, Note 11, included elsewhere in this Form
10-K."
CUSTOMERS
Our customers include major and independent natural gas and oil producers,
pipeline transmission companies and offshore engineering and construction firms.
The level of construction services required by any particular customer depends
on the size of that customer's capital expenditure budget devoted to
construction plans in a particular year. Consequently, customers that account
for a significant portion of contract revenues in one fiscal year may represent
an immaterial portion of contract revenues in subsequent fiscal years. We
estimate that in 1999 we provided subsea services to approximately 100
customers. EEX Corporation, accounted for 13% of consolidated revenues in 1999.
In addition, Chevron USA accounted for 11% of
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consolidated revenues in 1998. Our projects are typically of short duration and
are generally awarded shortly before mobilization. Accordingly, backlog is not a
meaningful indicator of future activities.
COMPETITION
The subsea services industry is highly competitive. Competition has
historically been based on factors such as the location and type of equipment
available, the ability to deploy such equipment, the safety and quality of
service and in recent years price. While price is a factor, the ability to
acquire specialized vessels, to attract and retain skilled personnel, and to
demonstrate a good safety record are important competitive factors. Our
competitors in the shallower waters of the Gulf include Stolt Offshore, Torch,
Inc., Global Industries Ltd. and Oceaneering International, Inc. as well as a
number of smaller companies, some of which only operate a single vessel, that
often compete solely on price. For Deepwater projects, our principal U.S. based
competitors include Oceaneering International, Inc., Global Industries, Ltd. and
Stolt Offshore. Other large foreign based subsea contractors, including,
Coflexip, DSND Ltd, Saipem and Rockwater, Ltd., may perform services in the
Gulf. We also encounter significant competition for the acquisition of producing
natural gas and oil properties. Our ability to acquire additional properties
also depends upon our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment. Many of our
competitors are well-established companies with substantially larger operating
staffs and greater capital resources.
TRAINING, SAFETY AND QUALITY ASSURANCE
We have established a corporate culture in which safety is understood to be
and is accepted as the number one priority. Our corporate goal, based on the
belief that all accidents are preventable, is to provide an injury-free
workplace by focusing on correct safety behavior. Our safety procedures and
training programs were developed by management personnel who came into the
industry as divers and who know first hand the physical challenge of the ocean
work site. As a result, management believes that our safety programs are among
the best in the industry.
GOVERNMENT REGULATION
Many aspects of the offshore marine construction industry are subject to
extensive governmental regulation. The Company is subject to the jurisdiction of
the United States Coast Guard ("Coast Guard"), the Environmental Protection
Agency, Minerals Management Service ("MMS") and the U.S. Customs Service
("USCS") as well as private industry organizations such as the American Bureau
of Shipping ("ABS").
We support and voluntarily comply with the Association of American Diving
Contractor Standards. The Coast Guard sets safety standards and is authorized to
investigate vessel and diving accidents and recommend improved safety standards,
and the Coast Guard is authorized to inspect vessels at will. We are required by
various governmental and quasi-governmental agencies to obtain certain permits,
licenses and certificates with respect to its operations. We believe that we
have obtained or can obtain all permits, licenses and certificates necessary for
the conduct of its business.
In addition, we depend on the demand for our services from the oil and gas
industry and, therefore, our business is affected by laws and regulations, as
well as changing taxes and policies relating to the oil and gas industry
generally. In particular, the development and operation of natural gas and oil
properties located on the Outer Continental Shelf ("OCS") of the United States
is regulated primarily by the MMS.
The MMS requires lessees of OCS properties to post bonds in connection with
the plugging and abandonment of wells located offshore and the removal of all
production facilities. Operators in the Outer Continental Shelf waters are
currently required to post an area wide bond of $3.0 million or $500,000 per
producing lease. We currently have bonded our offshore leases as required by the
MMS. Under certain circumstances, the MMS has the authority to suspend or
terminate operations on federal leases. Any such
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suspensions or terminations of our operations could have a material adverse
effect on our financial condition and results of operations.
We acquire production rights to offshore mature oil and gas properties
under federal oil and gas leases, which the MMS administers. These leases
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act
("OCSLA") (which are subject to change by the MMS). The MMS has promulgated
regulations requiring offshore production facilities located on the Outer
Continental Shelf to meet stringent engineering and construction specifications.
These latter regulations were withdrawn pending further discussions among
interested federal agencies. The MMS also has issued regulations restricting the
flaring or venting of natural gas and prohibiting the burning of liquid
hydrocarbons without prior authorization. Similarly, the MMS has promulgated
other regulations governing the plugging and abandonment of wells located
offshore and the removal of all production facilities. Finally, under certain
circumstances, the MMS may require any operations on federal leases to be
suspended or terminated, and the MMS has recently proposed, but not yet enacted,
regulations that would allow it to expel unsafe operators from existing Outer
Continental Shelf platforms and bar them from obtaining future leases.
The MMS has issued a final rule governing the calculation of royalties and
the valuation of crude oil produced from federal leases. The rule modifies the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on oil posted prices and assign a value to
crude oil that better reflects market value, establishes a new MMS form for
collecting value differential data, and amend the valuation procedure for the
sale of federal royalty oil. This rule might affect our operation. In addition,
the MMS recently issued a final rule amending its regulations regarding costs
for gas transportation which are deductible for royalty valuation purposes when
gas is sold offlease. Among other matters, for purposes of computing royalty
owed, the rule disallows as deductions certain costs, such as
aggregator/marketer fees and transportation imbalance charges and associated
penalties. The rule, however, was enjoined on March 28, 2000.
Historically, the transportation and sale for resale of natural gas in
interstate commerce has been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the
past, the federal government has regulated the prices at which gas and oil could
be sold. While sales by producers of natural gas, and all sales of crude oil,
condensate, and natural gas liquids can currently be made at uncontrolled market
prices, Congress could reenact price controls in the future. Deregulation of
wellhead sales in the natural gas industry began with the enactment of the NGPA.
In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended
the NGPA to remove both price and non-price controls from natural gas sold in
"first sales" no later than January 1, 1993.
Sales of natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation remain
subject to extensive federal and state regulation. Several major regulatory
changes have been implemented by Congress and the FERC from 1985 to the present
that affect the economics of natural gas production, transportation and sales.
In addition, the FERC continues to promulgate revisions to various aspects of
the rules and regulations affecting those segments of the natural gas industry,
most notably interstate natural gas transmission companies that remain subject
to the FERC's jurisdiction. These initiatives may also affect the intrastate
transportation of gas under certain circumstances. The stated purpose of many of
these regulatory changes is to promote competition among the various sectors of
the natural gas industry. The ultimate impact of the complex rules and
regulations issued by the FERC since 1985 cannot be predicted. In addition, many
aspects of these regulatory developments have not become final but are still
pending judicial and FERC final decisions.
We cannot predict what further action the FERC will take on these matters,
however, we do not believe that we will be affected by any action taken
materially differently than other companies with which we compete.
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<PAGE> 11
Additional proposals and proceedings before various federal and state
regulatory agencies and the courts could affect the oil and gas industry. We
cannot predict when or whether any such proposals may become effective. In the
past, the natural gas industry has been heavily regulated. There is no assurance
that the regulatory approach currently pursued by the FERC will continue
indefinitely. Notwithstanding the foregoing, we do not anticipate that
compliance with existing federal, state and local laws, rules, and regulations
will have a material effect upon the capital expenditures, earnings, or
competitive position.
ENVIRONMENTAL REGULATIONS
Our operations are subject to a variety of federal, state and local laws
and regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Numerous governmental
departments issue rules and regulations to implement and enforce such laws that
are often complex and costly to comply with, and that carry substantial
administrative, civil and possibly criminal penalties for failure to comply.
Aside from possible liability for damages and costs associated with releases of
hazardous materials including oil into the environment, such laws and
regulations may impose liability on us for the conduct of or conditions caused
by others, or by our acts that were in compliance with all applicable laws at
the time such acts were performed.
The Oil Pollution Act of 1990, as amended ("OPA"), imposes a variety of
requirements on "responsible parties" related to the prevention of oil spills
and liability for damages resulting from such spills in waters of the United
States. A "responsible party" includes the owner or operator of an onshore
facility, vessel or pipeline, or the lessee or permittee of the area in which an
offshore facility is located. OPA imposes liability on each responsible party
for oil spill removal costs and for other public and private damages from oil
spills. Failure to comply with OPA may result in the assessment of civil and
criminal penalties. OPA establishes liability limits of up to $350 million for
onshore facilities, all removal costs plus up to $75 million for offshore
facilities, and the greater of $500,000 or $600 per gross ton for vessels other
than tank vessels. The liability limits are not applicable, however, if the
spill is caused by gross negligence or willful misconduct, if the spill resulted
from violation of a federal safety, construction, or operating regulation, or if
a party fails to report a spill or fails to cooperate fully in the cleanup. Few
defenses exist to the liability imposed under OPA. Management is currently
unaware of any oil spills for which we have been designated as a responsible
party under OPA that will have a material adverse impact on us or our
operations.
OPA also imposes ongoing requirements on a responsible party including
preparation of an oil spill contingency plan and proof of financial
responsibility to cover a majority of the costs in a potential spill. We believe
we have appropriate spill contingency plans in place. Vessels subject to OPA
other than tank vessels are subject to financial responsibility limits of the
greater of $500,000 or $600 per gross ton, while offshore facilities are subject
to financial responsibility limits of not less than $35 million, with that limit
potentially increasing up to $150 million if a formal risk assessment indicates
that a greater amount is required. The MMS has promulgated regulations
implementing these financial responsibility requirements for covered offshore
facilities. Under the MMS regulations, the amount of financial responsibility
required for an offshore facility is increased above the minimum amounts of the
"worst case" oil spill volume calculated for the facility. We believe that we
currently have established adequate proof of financial responsibility for our
vessels and onshore and offshore facilities and that we satisfy the MMS
requirements for financial responsibility under OPA and the proposed
regulations.
OPA also requires owners and operators of vessels over 300 gross tons to
provide the Coast Guard with evidence of financial responsibility to cover the
cost of cleaning up oil spills from such vessels. We currently own and operate
six vessels over 300 gross tons. Satisfactory evidence of financial
responsibility has been provided to the Coast Guard for all of our vessels.
The Clean Water Act imposes strict controls on the discharge of pollutants
into the navigable waters of the U.S., and imposes potential liability for the
costs of remediating releases of petroleum and other substances. The Clean Water
Act provides for civil, criminal and administrative penalties for any
unauthorized discharge of oil and other hazardous substances and imposes
substantial potential liability for the costs of removal, remediation and
damages. Many states have laws which are analogous to the Clean Water Act and
9
<PAGE> 12
also require remediation of releases of petroleum and other hazardous substances
in state waters. Our vessels routinely transport diesel fuel to offshore rigs
and platforms, and also carry diesel fuel for their own use. Our supply boats
transport bulk chemical materials used in drilling activities, and also
transport liquid mud which contains oil and oil by-products. Offshore facilities
and vessels operated by us have facility and vessel response plans to deal with
potential spills of oil or its derivatives.
OCSLA provides the federal government with broad discretion in regulating
the release of offshore resources of natural gas and oil production as well as
regulating safety and environmental protection applicable to lessees and
permittees operating in the Outer Continental Shelf. Specific design and
operational standards may apply to Outer Continental Shelf vessels, rigs,
platforms, vehicles and structures. Violations of lease conditions or
regulations issued pursuant to OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing operations
and cancellation of leases. Because our operations rely on offshore oil and gas
exploration and production, if the government were to exercise its authority
under OCSLA to restrict the availability of offshore oil and gas leases, such
action could have a material adverse effect on our financial condition and the
results of operations. As of this date, we believe we are not the subject of any
civil or criminal enforcement actions under OCSLA.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA") contains provisions dealing with remediation of releases of hazardous
substances into the environment and imposes liability without regard to fault or
the legality of the original conduct, on certain classes of persons including
owners and operators of contaminated sites where the release occurred and those
companies who transport, dispose of or who arrange for disposal of hazardous
substances released at the sites. Under CERCLA, such persons may be subject to
joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, for damages to natural
resources and for the costs of certain health studies. Third parties may also
file claims for personal injury and property damage allegedly caused by the
release of hazardous substances. Although we handle hazardous substances in the
ordinary course of business, we are not aware of any hazardous substance
contamination for which we may be liable.
Management believes we are in compliance in all material respects with all
applicable environmental laws and regulations to which we are subject. We do not
anticipate that compliance with existing environmental laws and regulations will
have a material effect upon the capital expenditures, earnings or competitive
position. However, changes in the environmental laws and regulations, or claims
for damages to persons, property, natural resources or the environment, could
result in substantial costs and liabilities and thus there can be no assurance
that we will not incur significant environmental compliance costs in the future.
EMPLOYEES
We rely on the high quality of our workforce and have successfully hired,
trained, and retained skilled managers and divers. As of December 31, 1999, we
had 883 employees, 138 of which were salaried. As of that date we also utilized
approximately 105 non-US citizens to crew our foreign flag vessels under a
crewing contract with C-MAR Services (UK), Ltd. of Aberdeen, Scotland. None of
our employees belong to a union or are employed pursuant to any collective
bargaining agreement or any similar arrangement. Management believes that our
relationship with our employees and foreign crew members is good. Of our
employees, approximately 94 persons own shares of Common Stock and 72 other
employees hold options to acquire Common Stock under the Company's 1995 Long
Term Incentive Plan, as amended.
FACTORS INFLUENCING FUTURE RESULTS AND
ACCURACY OF FORWARD LOOKING INFORMATION
Shareholders should carefully consider the following risk factors in
addition to the other information contained in this Annual Report. This Annual
Report on Form 10-K includes certain statements that may be deemed
"forward-looking statements" within the meaning of Section 27A of the Securities
Act and Section 21E of the Exchange Act. All statements, other than statements
of historical facts, included in this Annual Report that relate to business
plans or strategies, projected or anticipated benefits or other
10
<PAGE> 13
consequences of such plans or strategies, projected or anticipated benefits from
acquisitions made by or to be made by us or projections involving anticipated
revenues, earnings, or other aspects of operating results are forward-looking
statements. The words "expect," "believe," "anticipate," "project," "estimate,"
and similar expressions are intended to identify forward-looking statements. We
caution readers that such statements are not guarantees of future performance or
events and are subject to a number of factors that may tend to influence the
accuracy of the statements and the projections upon which the statements are
based, including but not limited to those discussed below. As noted elsewhere,
all phases of our operations are subject to a number of uncertainties, risks and
other influences, many of which are outside our control, and any one or a
combination of which could materially affect the results of our operations and
the accuracy of forward-looking statements made by us. The following discussion
outlines certain factors that could affect our consolidated results of
operations for 2000 and beyond and cause them to differ materially from those
that may be set forth in forward-looking statements made by or on our behalf.
OUR BUSINESS IS ADVERSELY AFFECTED BY LOW OIL AND GAS PRICES AND BY THE
CYCLICALITY OF THE OIL AND GAS INDUSTRY.
Our business is substantially dependent upon the condition of the oil and
gas industry and, in particular, the willingness of oil and gas companies to
make capital expenditures on exploration, drilling and production operations
offshore. The level of capital expenditures generally depends on the prevailing
view of future oil and gas prices, which are influenced by numerous factors
affecting the supply and demand for oil and gas, including worldwide economic
activity, interest rates and the cost of capital, environmental regulation, tax
policies, coordination by the Organization of Petroleum Exporting Countries
("OPEC"), the cost of exploring for and producing oil and gas, the sale and
expiration dates of offshore leases in the United States and overseas, the
discovery rate of new oil and gas reserves in offshore areas and technological
advances. The level of offshore drilling and production activity did not
increase the second half of 1999 despite higher commodity prices. There can be
no assurance that activity levels will increase any time soon. A sustained
period of low drilling and production activity or a return of low hydrocarbon
prices would likely have a material adverse effect on our financial position and
results of operations.
THE OPERATION OF MARINE VESSELS IS RISKY AND WE DO NOT HAVE INSURANCE COVERAGE
FOR ALL RISKS.
Marine construction involves a high degree of operational risk. Hazards,
such as vessels sinking, grounding, colliding and sustaining damage from severe
weather conditions, are inherent in marine operations. These hazards can cause
personal injury or loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.
Damage arising from such an occurrence may result in lawsuits asserting large
claims. We maintain such insurance protection as we deem prudent, including
Jones Act employee coverage (the maritime equivalent of workers compensation)
and hull insurance on our vessels and have never had a claim involving major
damage or pollution involving our vessels. There can be no assurance that any
such insurance will be sufficient or effective under all circumstances or
against all hazards to which we may be subject. A successful claim for which we
are not fully insured could have a material adverse effect on us. Moreover, no
assurance can be given that we will be able to maintain adequate insurance in
the future at rates that we consider reasonable. As construction activity moves
into deeper water in the Gulf of Mexico, construction projects tend to be larger
and more complex than shallow water projects. As a result, our revenues and
profits are increasingly dependent on our larger vessels. While we currently
insure our vessels against property loss due to a catastrophic marine disaster,
mechanical failure or collision, the loss of any of our large vessels as a
result of such event could result in a substantial loss of revenues, increased
costs and other liabilities and could have a material adverse effect on our
operating performance. To date, we have not been involved in any such
significant claims or litigation.
OUR BUSINESS DECLINES IN WINTER AND BAD WEATHER IN THE GULF OF MEXICO CAN
ADVERSELY AFFECT OUR OPERATIONS.
Marine operations conducted in the Gulf of Mexico are seasonal and depend,
in part, on weather conditions. Historically, we have enjoyed our highest vessel
utilization rates during the summer and fall when
11
<PAGE> 14
weather conditions are favorable for offshore exploration, development and
construction activities and have experienced our lowest utilization rates in the
first quarter. During certain periods of the year, we typically bear the risk of
delays caused by adverse weather conditions. Accordingly, the results of any one
quarter are not necessarily indicative of annual results or continuing trends.
IF WE BID TOO LOW ON A CONTRACT WE SUFFER THE CONSEQUENCES.
A majority of our projects are currently performed on a qualified turnkey
basis where described work is delivered for a fixed price and extra work is
charged separately. The revenue, cost and gross profit realized on a contract
can vary from the estimated amount because of changes in offshore job
conditions, variations in labor and equipment productivity from the original
estimates and performance of others such as alliance partners. These variations
and risks inherent in the marine construction industry may result in our
experiencing reduced profitability or losses on projects.
THE ESTIMATES OF OUR NATURAL GAS AND OIL RESERVES AND FUTURE CASH FLOWS MAY BE
SIGNIFICANTLY INCORRECT.
This report contains an estimate of our proved natural gas and oil reserves
and the estimated future net cash flows therefrom based upon a report prepared
as of December 31, 1999 by Miller & Lents. That report relies upon various
assumptions, including assumptions required by the Securities and Exchange
Commission as to natural gas and oil prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. The process of estimating
natural gas and oil reserves is complex, requiring significant decisions and
assumptions in the evaluation of available geological, geophysical, engineering
and economic data for each reservoir. As a result, these estimates are
inherently imprecise. Actual future production, cash flows, development
expenditures, operating expenses and quantities of recoverable natural gas and
oil reserves may vary substantially from those estimated in the report. Any
significant variance in these assumptions could materially affect the estimated
quantity and value of our proved reserves.
OUR NATURAL GAS AND OIL OPERATIONS INVOLVE SIGNIFICANT RISKS AND WE DO NOT HAVE
INSURANCE COVERAGE FOR ALL RISKS.
Our natural gas and oil operations are subject to the usual risks incident
to the operation of natural gas and oil wells, including, but not limited to,
uncontrollable flows of oil, natural gas, brine or well fluids into the
environment, blowouts, cratering, mechanical difficulties, fires, explosions,
pollution and other risks, any of which could result in substantial losses to
us. Although we have had no significant claims of this nature to date, in
accordance with industry practice, we maintain insurance against some, but not
all, of the risks described above.
WE MAY NOT BE ABLE TO COMPETE SUCCESSFULLY AGAINST CURRENT AND FUTURE
COMPETITORS.
The business in which we operate is highly competitive. Several of our
competitors are companies that are substantially larger and have greater
financial and other resources than we have. If other companies relocate or
acquire vessels for operations in the Gulf of Mexico, levels of competition may
increase and our business could be adversely affected.
THE LOSS OF THE SERVICES OF ONE OR MORE OF OUR KEY PERSONNEL, OR OUR FAILURE TO
ATTRACT, ASSIMILATE AND RETAIN OTHER HIGHLY QUALIFIED PERSONNEL IN THE FUTURE,
COULD DISRUPT OUR OPERATIONS AND RESULT IN LOSS OF NET SALES.
Our success depends on the continued active participation of key management
personnel. The loss of key people could adversely affect our operations. We have
multi-year employment and non-compete agreements with all of our senior
officers. We believe that our success and continued growth is also dependent
upon our ability to employ and retain skilled personnel. While we believe that
our wage rates are competitive and that our relationship with our workforce is
good, a significant increase in the wages paid by other employers could result
in a reduction in the Company's workforce, increases in the wage rates we pay,
or both. If either of these
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<PAGE> 15
events occur for any significant period of time, our profitability could be
diminished and our growth potential could be impaired.
WE MAY NEED TO CHANGE THE MANNER IN WHICH WE CONDUCT ONE BUSINESS IF GOVERNMENT
REGULATION INCREASES.
Our subsea construction, inspection, maintenance and decommissioning
operations and our natural gas and oil production from offshore properties
(including decommissioning of such properties) are subject to and affected by
various types of government regulation, including numerous federal, state and
local environmental protection laws and regulations. These laws and regulations
are becoming increasingly complex, stringent and expensive and there can be no
assurance that continued compliance with existing or future laws or regulations
will not adversely affect our operations. Significant fines and penalties may be
imposed for non-compliance.
CERTAIN PROVISIONS OF OUR CORPORATE DOCUMENTS AND MINNESOTA LAW MAY DISCOURAGE A
THIRD PARTY FROM MAKING A TAKEOVER PROPOSAL.
Our Board of Directors has the authority, without any action by the
stockholders, to fix the rights and preferences on up to 5,000,000 shares of
undesignated preferred stock, including dividend, liquidation and voting rights.
In addition, our Articles of Incorporation divide the board of directors into
three classes. Except for a transaction involving Coflexip (which is
specifically excluded), we are also subject to certain anti-takeover provisions
of the Minnesota Business Corporations Act. In addition, we are a party to a
Shareholders Agreement that provides Coflexip with a right of first refusal in
connection with certain acquisition proposals and we have employment contracts
with all of our senior officers which require accelerated vesting of stock
options and cash payments in the event of a "change of control". Any or all of
the provisions or factors described above may have the effect of discouraging a
takeover proposal or tender offer not approved by management and the board of
directors and could result in stockholders who may wish to participate in such a
proposal or tender offer receiving less for their shares than otherwise might be
available in the event of a takeover attempt.
ITEM 2. PROPERTIES.
MARINE VESSELS AND EQUIPMENT
General
We own a fleet of 15 vessels and one ROV. The size of our fleet and its
capabilities have increased in 1999 with the addition of three (3) smaller
Aquatica vessels and the DP DSV Cal Dive Aker Dove.
Management believes that the Gulf of Mexico market requires specially
designed or equipped vessels to deliver the necessary subsea construction
services, especially in the Deepwater. Six of our vessels have DP capabilities
specifically designed to respond to the Deepwater market. Five of our vessels
also have the permanent capability to provide SAT diving services.
New Vessels
To gain a greater share of the Deepwater market, in mid-1999 we commenced
construction of the world's first sixth-generation multi-service vessel, the MSV
Q4000. The vessel is designed to be a new generation of the MSV Uncle John and
is unique due to the absence of lower hull cross bracing. Variable deck load of
approximately 4,000 metric tons makes the vessel particularly well suited for
large offshore construction projects in the Deepwater. High transit speed will
allow it to move rapidly from one location to another. We are currently in the
process of applying to the US government for construction and permanent MARAD
financing on attractive terms. Although no commitment has been obtained from
MARAD, management plans to close a financing during the second quarter of 2000
and will fund construction costs in the interim with operating cash and our bank
line of credit.
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<PAGE> 16
In June of 1999, we purchased a controlling interest in the DP anchor
handling vessel Cal Dive Aker Dove. The vessel is 279 feet long, 65 feet wide,
has accommodations for 52 people, a large deck area of 7700 square feet and 1500
tons of deck load capacity. Lifting capability is from a 300 ton A-Frame. In
addition to supporting our other vessels, she will provide new up-stream
services not previously performed by us, including anchor handling, wire
inserts, preset mooring installation, towing, FPSO installation,
template/manifold/foundation lowering and supply boat mooring.
We contracted to have a replacement vessel built for our utility boat Cal
Diver IV as part of our ongoing program to upgrade the quality of our fleet. The
original Cal Diver IV was sold to Aquatica in January 1999 (and renamed the Mr.
Joe). The new vessel will be 120 feet long, 32 feet wide, have 1,440 feet of
clear deck space, a 60 ton deck load capacity and galley accommodations for 24
people. It will be capable of 10 knots cruising speed and is expected to be
delivered in 2000.
In 1998 we acquired the Sea Sorceress as a DP conversion candidate given
her hull (3-inch thick steel) and massive deck capable of carrying a 10,000
metric ton load. In 1999 the vessel was moved to the same Amfels drydock where
the Q4000 is being built. The move was due to her Canadian work contract being
cancelled. The conversion of the Sea Sorceress (or the acquisition of a
similarly configured vessel) is planned in 2000.
CAL DIVE INTERNATIONAL, INC.
LISTING OF VESSELS, BARGES AND ROVS
AS OF DECEMBER 31, 1999
<TABLE>
<CAPTION>
DATE CLEAR DECK MOONPOOL
PLACED IN LENGTH SPACE DECK LOAD ACCOM- LAUNCH/
SERVICE (FEET) (SQ. FEET) (TONS) MODATIONS SAT DIVING CRANE CLASSIFICATION(2)
--------- ------ ---------- --------- --------- ---------- ----------- -----------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
DP MSV:
Uncle John.............. 11/96 254 11,834 460 102 X 2 x 100-ton DNV
DP DSVS:
Balmoral Sea............ 9/94 259 3,443 250 60 X 30-ton DNV
Witch Queen............. 11/95 278 5,600 500 60 X 50-ton DNV
Merlin.................. 12/97 198 955 308 42 -- A-Frame ABS
Cal Dive Aker Dove...... 9/99 279 7,700 1,500 52 -- 300 ton ABS
A-Frame
CDI DSVS:
Cal Diver I............. 7/84 196 2,400 220 40 X 20-ton ABS
Cal Diver II............ 6/85 166 2,816 300 32 X A-Frame ABS
Cal Diver V............. 9/91 168 2,324 490 30 -- A-Frame ABS
AQUATICA DSVS:
Cal Diver III........... 8/87 115 1,320 105 18 -- -- ABS
Cal Dive IV(1).......... 2000 120 1,440 60 24 -- -- ABS
Mr. Jim................. 2/98 110 1,210 64 19 -- -- USCG
Mr. Joe................. 1/99 100 1,035 46 16 -- -- USCG
Mr. Jack................ 1/98 120 1,220 66 22 -- -- USCG
OTHER:
Sea Sorceress........... 8/97 374 8,600 10,000 50 -- -- DNV
Cal Dive Barge I........ 8/90 150 NA 200 26 -- 200-ton ABS
ROV..................... 4/97 25 -- -- -- -- -- --
</TABLE>
- ---------------
(1) Delivery of this vessel is expected in 2000.
(2) Under government regulations and our insurance policies, we are required to
maintain our vessels in accordance with standards of seaworthiness and
safety set by government regulations and classification organizations. Those
standards are set by various organizations such as American Bureau of
Shipping ("ABS"), Det Norske Veritas ("DNV") and the Coast Guard. The ABS is
one of several classification societies used by ship owners to certify that
their vessels meet certain structural, mechanical and safety equipment
standards, including Lloyd's Register, Bureau Veritas and DNV among others.
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<PAGE> 17
We incur routine drydock inspection, maintenance and repair costs under
Coast Guard Regulations and to maintain ABS or DNV classification for our
vessels. In addition to complying with these requirements, we have our own
vessel maintenance program which management believes permits us to continue to
provide our customers with well maintained, reliable vessels. In the normal
course of our operations, we also charter other vessels on a short-term basis,
such as tugboats, cargo barges, utility boats and dive support vessels. All of
our vessels are subject to ship mortgages.
SUMMARY OF NATURAL GAS AND OIL RESERVE DATA
The table below sets forth information, as of December 31, 1999, with
respect to our estimated net proved reserves and the present value of estimated
future net cash flows at such date, based on estimates by Miller & Lents.
<TABLE>
<CAPTION>
TOTAL PROVED
(DOLLARS IN
THOUSANDS)
------------
<S> <C>
Estimated Proved Reserves:
Natural Gas (MMcf)........................................ 25,381
Oil and Condensate (MBbls)................................ 1,702
Standardized measure of discounted future net cash flows
(pre-tax)................................................. $37,852
-------
</TABLE>
- ---------------
(1) Six (6) blocks purchased in February of 2000 are not included in the above
December 31, 1999 summary. As a result of this purchase, ERT's Estimated
Proven Reserves have increased approximately 24% to 31,560 Mmcf of natural
gas and 1,702 MBbls of oil and the standardized measure of discounted future
net cash flow has increased to $39,827 (pre-tax).
(2) The standardized measure of discounted future net cash flows attributable to
our reserves was prepared using constant prices as of the calculation date,
discounted at 10% per annum.
As of March 24, 2000, we owned an interest in 137 gross (105 net) natural
gas wells and 74 gross (51 net) oil wells located in federal offshore waters in
the Gulf of Mexico.
FACILITIES
Our headquarters is at 400 N. Sam Houston Parkway E., in Houston, Texas.
Our primary subsea and marine services operations are based in Morgan City,
Louisiana. All of our facilities are leased.
PROPERTY AND FACILITIES SUMMARY
<TABLE>
<CAPTION>
FUNCTION SIZE
------------------------------ ------------------
<S> <C> <C>
Houston, Texas...................... Corporate and ERT Headquarters 37,800 square feet
Project Management
Sales Office
Morgan City, Louisiana.............. Operations/Docking 28.5 acres
Warehouse 30,000 square feet
Offices 4,500 square feet
Lafayette, Louisiana (Aquatica,
Inc.)............................. Operations 8 acres
Warehouse 12,000 square feet
Offices 5,500 square feet
</TABLE>
We also have sales offices in Lafayette and Harvey, Louisiana.
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<PAGE> 18
ITEM 3. LEGAL PROCEEDINGS.
Our operations are subject to the inherent risks of offshore marine
activity, including accidents resulting in personal injury and the loss of life
or property, environmental mishaps, mechanical failures and collisions. We
insure against these risks at levels consistent with industry standards. We
believe our insurance is adequate to protect us against, among other things, the
cost of replacing the total or constructive total loss of our vessels. We also
carry workers' compensation, maritime employer's liability, general liability
and other insurance customary in our business. All insurance is carried at
levels of coverage and deductibles that we consider financially prudent. Our
services are provided in hazardous environments where accidents involving
catastrophic damage or loss of life could result, and litigation arising from
such an event may result in our being named a defendant in lawsuits asserting
large claims. To date, we have been involved in no such catastrophic claim or
lawsuit. Although there can be no assurance that the amount of insurance we
carry is sufficient to protect us fully in all events, management believes that
our insurance protection is adequate for our business operations. A successful
liability claim for which we are underinsured or uninsured could have a material
adverse effect on our business.
We are involved in various legal proceedings primarily involving claims for
personal injury under the General Maritime Laws of the United States and the
Jones Act as a result of alleged negligence. In addition, we from time to time
incur other claims, such as contract disputes, in the normal course of business.
In that regard, CDI entered into a subcontract with Seacore Marine Contractors
Limited to provide the Sea Sorceress for the excavation of glory holes in
Canada. Due to unforeseen difficulties with respect to the sea states and soil
conditions the contract was terminated. Seacore was provided a performance bond
of $5 million with respect to the subcontract. No call has been made on this
bond and Seacore and CDI believe the contract was wrongfully terminated and are
vigorously defending this claim and seeking damages in arbitration. We believe
that the outcome of this and all other such proceedings, even if determined
adversely, would not have a material adverse effect on our business or financial
condition.
ITEM 4. SUBMISSION OF MAKERS TO A VOTE OF SECURITY HOLDERS.
None.
ITEM (UNNUMBERED). EXECUTIVE OFFICERS OF THE COMPANY
The following table sets forth certain information as of December 31, 1999
with respect to the executive officers and certain other senior officers of the
Company:
<TABLE>
<CAPTION>
NAME AGE POSITION WITH THE COMPANY
- ---- --- -------------------------
<S> <C> <C>
Owen Kratz............................ 46 Chairman and Chief Executive Officer
Martin R. Ferron...................... 43 President and Chief Operating Officer
S. James Nelson, Jr. ................. 57 Executive Vice President and Chief
Financial Officer
Andrew C. Becher...................... 54 Senior Vice President, General Counsel
and Secretary
Louis L. Tapscott..................... 62 Senior Vice President -- Special
Projects
Kenneth Duell......................... 48 Senior Vice President -- Business
Development
Lyle K. Kuntz......................... 48 President, Energy Resource Technology,
Inc.
Prentiss A. (Sonny) Freeman........... 52 President, Aquatica
A. Wade Pursell....................... 35 Vice President -- Finance
</TABLE>
Owen Kratz has served as our Chairman since May of 1998, Chief Executive
Officer since April 1997, President since 1993 and Chief Operating Officer and
director since 1990. He joined the Company in 1984 and has held various offshore
positions, including SAT diving supervisor, and management responsibility for
client relations, marketing and estimating. From 1982 to 1983, Mr. Kratz was the
owner of an independent marine
16
<PAGE> 19
construction company operating in the Bay of Campeche. Prior to 1982, he was a
supervisor for various international diving companies and a SAT diver in the
North Sea.
Martin R. Ferron became President in February of 1999, has served as Chief
Operating Officer since January 1998 and has been a Director since 1998. Mr.
Ferron has twenty years of worldwide experience in the oilfield industry, seven
of which were in senior management positions with international operations of
McDermott Marine Construction and Oceaneering International Services Limited.
Mr. Ferron has a Civil Engineering degree, a Masters Degree in Marine
Technology, an MBA and is a Chartered Civil Engineer.
S. James Nelson, Jr., has served as Executive Vice President and Chief
Financial Officer and Director of the Company since 1990. From 1985 to 1988, Mr.
Nelson was the Senior Vice President and Chief Financial Officer of Diversified
Energies, Inc., the former parent of Cal Dive, at which time he had corporate
responsibility for the Company. From 1980 to 1985, Mr. Nelson served as Chief
Financial Officer of Apache Corporation, an oil and gas exploration and
production company. From 1966 to 1980, Mr. Nelson was employed with Arthur
Andersen & Co., and from 1976 to 1980, he was a partner serving on the firm's
worldwide oil and gas industry team. Mr. Nelson received his undergraduate
degree from Holy Cross College (B.S.) in 1964 and a masters in business
administration (M.B.A.) from Harvard University in 1966.
Andrew C. Becher has served as Senior Vice President, General Counsel and
Secretary of the Company since January 1996. Mr. Becher served as outside
general counsel for the Company from 1990 to 1996, while a partner with the
national law firm Robins, Kaplan, Miller & Ciresi. From 1987 to 1990, Mr. Becher
served as Senior Vice President of Dain Raucher, Inc., a regional investment
banking firm. From 1976 to 1987, he was a partner specializing in mergers and
acquisitions with the law firm of Briggs & Morgan in Minneapolis.
Louis L. Tapscott joined the Company as Senior Vice President in August
1996. From 1992 to 1996, he was a Senior Vice President for Sonsub
International, Inc., a company which operates a Deepwater fleet of ROVs. From
1984 to 1988, he was a director and Chief Operating Officer of Oceaneering
International, Inc. Mr. Tapscott has over thirty years of executive management
and operational experience working with subsea contractors and subsea technology
organizations in the United States and internationally.
Kenneth Duell joined Cal Dive in November of 1994 and was appointed Senior
Vice President -- Business Development in 1997. From 1989 to 1994, he was
employed by ABB Soimi, Milan, Italy, in connection with a modular refining
systems development in Central Asia. From 1974 to 1988, he held various
positions with Santa Fe International, including the ROV and diving division.
Mr. Duell has over 22 years of worldwide experience in all aspects of the
onshore and offshore construction and diving industry.
Lyle Kuntz has served as President of our subsidiary, Energy Resource
Technology, Inc., since its inception in 1992. Prior to forming ERT, Mr. Kuntz
spent 17 years with ARCO Oil and Gas Co. in a broad range of senior engineering
and management positions.
A. Wade Pursell joined the Company in May 1997 as Vice President-Finance
and Chief Accounting Officer. From 1988 through 1997 he was with Arthur Andersen
LLP, most recently as an Experienced Manager specializing in the offshore
services industry. Mr. Pursell is a Certified Public Accountant.
Prentiss A. (Sonny) Freeman became President of Aquatica in October of
1997. Mr. Freeman has more than thirty years of experience in the Gulf of Mexico
oilfield service industry, twenty-two of which have been in senior management
and sales roles including twelve years as chief operating officer of American
Oilfield Divers (now part of Stolt Offshore). In 1997 he purchased Acadiana
Divers which changed its name to Aquatica and in 1999 sold Aquatica to CDI where
he retained his role as its President.
17
<PAGE> 20
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS.
Our Common Stock is traded in the U.S. on the Nasdaq National Market
("Nasdaq"). The Common Stock is quoted through Nasdaq under the symbol "CDIS."
The following table represents for the periods indicated, the high and low
closing sales price per share of our Common Stock:
<TABLE>
<CAPTION>
HIGH LOW
----------- -----------
<S> <C> <C>
Fiscal Year 1997
Third quarter(1).......................................... $ 37.75 $ 19.75
Fourth quarter............................................ 38.00 22.25
Fiscal Year 1998
First quarter............................................. $ 33.00 $ 23.25
Second quarter............................................ 39.375 26.00
Third quarter............................................. 28.125 12.25
Fourth quarter............................................ 22.6875 12.00
Fiscal Year 1999
First quarter............................................. $ 22.00 $ 14.25
Second quarter............................................ 32.6875 22.75
Third quarter............................................. 38.00 29.625
Fourth quarter............................................ 37.6875 20.00
Fiscal Year 2000
First quarter (through March 29, 2000).................... $51.0625 $31.5938
</TABLE>
- ---------------
(1) We completed our initial public offering on July 7, 1997 and trading
information in the third quarter of 1997 is reported only after that date.
As of March 24, 2000 there were approximately 2,400 holders of record of
Common Stock.
We have never paid cash dividends on its Common Stock and do not intend to
pay cash dividends in the foreseeable future. We currently intend to retain
earnings, if any, for the future operation and growth of our business. Certain
of our financing arrangements restrict the payment of cash dividends under
certain circumstances. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources".
In July of 1999, we issued 696,380 shares of common stock pursuant to
Section 4(2) of the Securities Act of 1933 in connection with the acquisition of
our subsidiary Aquatica.
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<PAGE> 21
ITEM 6. SELECTED FINANCIAL DATA
The financial data presented below for each of the five years ended
December 31, 1999, should be read in conjunction with Management's Discussion
and Analysis of Financial Condition and Results of Operations and the
Consolidated Financial Statements and Notes to Consolidated Financial Statements
included elsewhere in this Form 10-K.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------
1995 1996 1997 1998 1999
------- ------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
Net Revenues.............................. $37,524 $76,122 $109,386 $151,887 $160,954
Gross Profit.............................. 8,849 22,086 33,685 49,209 37,251
Net Income................................ 2,674 8,435 14,482 24,125 16,899
Net Income Per Share:
Basic................................... 0.24 0.76 1.12 1.66 1.13
Diluted................................. 0.24 0.75 1.09 1.61 1.10
EBITDA.................................... 6,650 19,017 29,916 45,544 44,805
Total Assets.............................. 44,859 83,056 125,600 164,235 243,722
Working Capital........................... 4,033 13,409 28,927 45,916 38,887
Long-Term Debt............................ 5,300 25,000 -- -- --
Shareholders' Equity...................... 22,408 30,844 89,369 113,643 150,872
</TABLE>
19
<PAGE> 22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
Natural gas and oil prices, the offshore mobile rig count and Gulf of
Mexico lease activity are three of the primary indicators management uses to
predict the level of the Company's business. CDI's construction services
generally follow successful drilling activities by six to eighteen months on the
Continental Shelf and twelve months or longer in the Deepwater arena. The level
of drilling activity is related to both short and long-term trends in natural
gas and oil prices. Commodity prices declined significantly in the last half of
1998 and early 1999 resulting in the utilization of offshore mobile rigs
dropping to approximately 70% in contrast to almost full utilization in 1997 and
the first half of 1998. This trend began reversing in the second quarter of 1999
such that oil prices have recently reached their highest level since the Gulf
War and natural gas prices are hovering in a range of $2.60/MCF to $2.80/MCF.
However, E&P companies have been hesitant to ramp up spending and accordingly
demand for the Company's services remained relatively soft throughout 1999.
Product prices impact the Company's natural gas and oil operations in
several respects. The Company seeks to acquire producing natural gas and oil
properties that are generally in the later stages of their economic life. These
properties typically have few, if any, unexplored drilling locations, so the
potential abandonment liability is a significant consideration with respect to
the offshore properties which the Company has purchased to date. Although higher
natural gas prices tend to reduce the number of mature properties available for
sale, these higher prices contributed to improved operating results for the
Company in 1996, 1997 and the second half of 1999. In contrast, lower natural
gas prices, as experienced in 1998 and early 1999, contributed to lower
operating results for ERT in those periods and generally increased the number of
mature properties acquired during those periods. Salvage operations consist of
platform decommissioning, removal and abandonment and P&A services performed by
the Company's salvage assets, i.e., a stiff-leg derrick barge and well servicing
equipment. In addition, salvage related support, such as debris removal and
preparation of platform legs for removal, is often provided by the Company's
surface diving vessels. In 1989, management targeted platform removal and
salvage operations as a regulatory driven activity which offers a partial hedge
against fluctuations in the commodity price of natural gas. In particular, MMS
regulations require removal of platforms within twelve months after lease
expiration and also require remediation of the seabed at the well site to its
original state. The Company contracts and manages, on a turnkey basis, all
aspects of the decommissioning and abandonment of fields of all sizes using
third party heavy lift derrick barges if necessary. The Company also has an
alliance with Horizon Offshore gaining access to expanded derrick barge and
pipelay capacity.
In 1999, CDI launched a new full field development product line to assist
cash constrained customers on the OCS. With 4,000 platforms and production
facilities already in place in the Gulf our underlying premise is that each new
field need not be re-engineered. Adapting industry standard designs we now stock
subsea trees, prefabricated modules, well panels and controls and umbilicals for
immediate assembly. That led to five full field/pipelay projects in 1999.
20
<PAGE> 23
The following table sets forth for the periods presented (i) average U.S.
natural gas prices, (ii) the Company's natural gas production, (iii) the average
number of offshore rigs under contract in the Gulf of Mexico, (iv) the number of
platforms installed and removed in the Gulf of Mexico and (v) the vessel
utilization rates for each of the major categories of the Company's fleet.
<TABLE>
<CAPTION>
1997 1998 1999
----------------------------- ----------------------------- -----------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
U.S. Natural Gas Prices(1)........ $2.67 $2.13 $2.46 $2.88 $2.18 $2.26 $2.03 $1.92 $1.80 $2.22 $2.53 $2.45
ERT Gas and Oil Production
(MMCFe)......................... 1,519 1,213 1,381 1,252 1,595 1,252 901 1,155 1,488 1,803 2,777 2,786
Rigs Under Contract in the Gulf of
Mexico(2)....................... 165 169 168 169 170 167 149 137 121 115 126 146
Platform Installations(3)......... 16 21 29 39 18 16 21 20 12 13 13 16
Platform Removals(3).............. 3 21 31 28 3 15 24 8 2 20 40 15
Average Company Vessel Utilization
Rate:(4)
Dynamic Positioned.............. 60% 79% 92% 94% 75% 64% 85% 80% 70% 49% 82% 69%
Saturation DSV.................. 58% 77% 81% 77% 88% 79% 70% 83% 54% 69% 79% 65%
Surface Diving.................. 53% 80% 90% 81% 33% 58% 72% 76% 63% 69% 78% 51%
Derrick Barge................... 22% 78% 99% 89% 28% 73% 70% 70% 40% 68% 83% 50%
</TABLE>
- ---------------
(1) Average of the monthly Henry Hub cash prices in $ per Mcf, as reported in
Natural Gas Week.
(2) Average monthly number of rigs contracted, as reported by Offshore Data
Services.
(3) Source: Offshore Data Services; installation and removal of platforms with
two or more piles in the Gulf of Mexico.
(4) Average vessel utilization rate is calculated by dividing the total number
of days the vessels in this category generated revenues by the total number
of days in each quarter (excluding Aquatica in 1999).
Vessel utilization is historically lower during the first quarter due to
winter weather conditions in the Gulf of Mexico. Accordingly, the Company plans
its drydock inspections and other routine and preventive maintenance programs
during this period. During the first quarter, a substantial number of the
Company's customers finalize capital budgets and solicit bids for construction
projects. During the second quarter of 1999, the Uncle John spent 30 days in
drydock undergoing thruster work and DNV inspections. The bid and award process
during the first two quarters leads to the commencement of construction
activities during the second and third quarters. As a result, the Company has
historically generated more than 50% (up to 65%) of its consolidated revenues in
the last six months of the year. The Company's operations can also be severely
impacted by weather during the fourth quarter. The Company's salvage barge,
which has a shallow draft, is particularly sensitive to adverse weather
conditions, and its utilization rate will be lower during such periods. To
minimize the impact of weather conditions on the Company's operations and
financial condition, CDI began operating DP vessels and expanded into the
acquisition of mature offshore properties. The unique station-keeping ability
offered by dynamic positioning enables these vessels to operate throughout the
winter months and in rough seas. Operation of natural gas and oil properties
tends to offset the impact of weather since the first and fourth quarters are
typically periods of high demand for natural gas and of strong natural gas
prices. Due to this seasonality, full year results are not likely to be a direct
multiple of any particular quarter or combination of quarters.
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<PAGE> 24
RESULTS OF OPERATIONS
Comparison of Year Ended December 31, 1999 to Year Ended December 31, 1998
Revenues. Consolidated revenues of $161 million in 1999 were 6% more than
the $151.9 million in 1998 with natural gas and oil production providing all of
the increase while Subsea operations revenues declined $10.9 million. Most of
this decline is due to 1998 revenues including $8 million from the charter of
two Coflexip Stena Offshore vessels. One project in 1999 (Cooper abandonment for
EEX) represented 13% of consolidated revenues. Adding the Cal Dive Aker Dove in
September 1999 and acquiring the remaining 55% of Aquatica, Inc., in August 1999
(and thus consolidating their results from that date forward) added $10 million
to 1999 revenues, while the subcontracting of derrick and pipelay barges also
added $10 million in 1999, offsetting the shortfall created by stacking the
Balmoral Sea nearly the entire first half of 1999.
Natural gas and oil production was $32.5 million in 1999 as compared to
$12.6 million in 1998. The increase was due mainly to a rise in production from
4.9 BCFE (billion of cubic feet equivalent) to 8.9 BCFE in 1999 as the number of
blocks owned by ERT was essentially doubled through property acquisitions during
the first four months of 1999. 1999 revenues were also assisted by improved
average gas prices ($2.35/MCF compared to $2.12 in 1998), an increase in oil
production and prices and the sale of three offshore leases.
Gross Profit. Gross profit decreased by $12 million, or 24%, from $49.2
million in 1998 to $37.3 million in 1999 despite an $8.4 million increase in
natural gas and oil production gross profit. The decrease in Subsea and Salvage
gross profit of $20.4 million is due to the $10.9 million revenue decline
discussed above coupled with margins declining from 33% in 1998 to 20% in 1999.
In addition to a decline in demand for CDI's services on the OCS in 1999
compared to 1998, the primary reason for the margin decline was CDI's shift to
prime contractor on eight major projects during 1999 which include high third
party pass through costs (such costs were 31% of revenues in 1999 compared to
23% in 1998).
Natural gas and oil production gross profit was $11.9 million in 1999 as
compared to $3.5 million in the prior year. The increase was due to the
aforementioned production improvement, gas and oil price increases and the gain
recorded on the sale of certain offshore blocks during 1999 offset by the
writedown of the carrying value of three ERT fields in connection with the 1999
Well Exploitation Program.
Selling and Administrative Expenses. Selling and administrative expenses
decreased $2.6 million in 1999 to $13.2 million as compared to $15.8 million in
1998. The primary reason for the decline was the lack of Subsea group bonuses
and staff reductions effected early in 1999. Consolidation of Aquatica the final
five months of 1999 added $1.2 million. SG&A for 1999 includes $3.7 million
related to ERT, an increase of $2.2 million over 1998 as we added new people to
handle the expansion in operations. That subsidiary's significantly increased
income also triggered significantly higher bonus payments under its incentive
program. Selling and administrative costs were 8% of revenues in 1999, two
margin points better than the 10% achieved in 1998.
Other Income and Expenses. The Company recorded $600,000 in 1999 for its
share of earnings in Aquatica, Inc., compared to $2.6 million in 1998 as
beginning August 1, 1999 Aquatica's results were consolidated with CDI's as a
result of the Company's acquisition of the remaining 55% ownership in Aquatica.
Net interest income of $849,000 was comparable to the $1.1 million earned in
1998 as CDI remained relatively debt free throughout both years.
Income Taxes. Income taxes were $8.5 million in 1999 compared to $13
million in 1998 due to the decreased profitability. The effective tax rate fell
from 35% in 1998 to 33% in 1999 due to research and development credits realized
as a result of CDI's operating at the forefront of Deepwater technology.
Net income. Net income decreased 30% in 1999 compared to 1998 as a result
of factors described above. Diluted earnings per share decreased slightly more
as a result of the additional shares issued in the Aquatica acquisition.
22
<PAGE> 25
Comparison of Year Ended December 31, 1998 to Year Ended December 31, 1997
Revenues. Consolidated revenues of $151.9 million in 1998 were 39% more
than the $109.4 million earned during 1997 with the Subsea operations
contributing all of the increase while natural gas and oil production revenues
declined $3.9 million. All of the increase was due to increased demand for
services provided by CDI's DP vessels, particularly the Uncle John, Witch Queen
and Balmoral Sea which together contributed 62% of the increase. In addition,
new vessels (Sea Sorceress and Merlin) contributed $10.3 million of the
increase. The charter of two Coflexip Stena Offshore vessels, the Marianos
during the first quarter and the Constructor in the second, added $8.0 million
to the 1998 revenues.
Natural gas and oil revenues were $12.6 million in 1998 as compared to
$16.5 million in 1997. The decrease was due to a decline in production from 5.7
BCFE during 1997 to 4.9 BCFE in 1998 and a decline in average gas prices from
$2.57/Mcf for 1997 to $2.12/Mcf during 1998. The decline in production is a
result of five wells going off line in the second quarter and remedial work
being delayed into the fourth quarter by a lack of equipment and then by
weather.
Gross Profit. Gross profit increased by $15.5 million, or 46%, from $33.7
million in 1997 to $49.2 million in 1998 with the Uncle John, Witch Queen and
Balmoral Sea making up the majority of the increase. The remaining increase was
due to improved demand for the two saturation diving vessels and the vessels
which work in the shallow Gulf of Mexico (from the shore to 300 feet of water).
Subsea and salvage margins increased from 27% in 1997 to 33% during 1998 due
mainly to outstanding offshore performance and demand for the DP vessels.
Natural gas and oil production gross profit was $3.5 million in 1998 as
compared to $8.4 million in the prior year. The decrease was due to the
aforementioned declines in average natural gas prices and production during 1998
as compared to 1997 and to expensive efforts to re-establish production in the
second half of the year.
Selling and Administrative Expenses. Selling and administrative expenses
increased $4.6 million to $15.8 million in 1998 as compared to 1997. The $15.8
million includes a $4.5 million provision principally for 1998 incentive
compensation compared to $2.9 million provided in 1997. The remainder of the
increase is due to the addition of new personnel to support the Company's
Deepwater strategy, growth in it base business and to the cost of a supply chain
management consulting project. Selling and administrative costs were 10% of
revenues in 1998, a level identical to that in 1997.
Other Income and Expenses. The Company recorded $2.6 million in 1998
reflecting its share of earnings of Aquatica, Inc. Net interest income and other
of $1.1 million for 1998 compares to $208,000 of net interest expense and other
for 1997. This improvement was due to the Company remaining debt free since
completion of its initial public offering of common stock in July, 1997.
Income Taxes. Income taxes were $13 million in 1998 as compared to $7.8
million for the prior year. The increase was due to the Company's increased
profitability as the effective tax rate remained 35% in both years. Roughly 35%
of the 1998 tax provision was deferred due mainly to increased depreciation in
addition to the Company's Deepwater research and development efforts.
Net Income. Net income increased 67% to $24.1 million in 1998 as compared
to $14.5 million in 1997 as a result of factors described above. Diluted
earnings per share increased 48% (19 percentage points less than the net income
increase) in 1998, as compared to 1997, due to the impact on weighted average
common shares outstanding of the new shares issued in the July 1997 IPO.
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically funded its operating activities principally
from internally generated cash flow, even during industry-depressed years such
as 1992 and 1998/1999. An initial public offering of common stock was completed
on July 7, 1997, with the sale of 2,875,000 shares generating net proceeds to
the Company of approximately $39.5 million, net of underwriting discounts and
issuance costs. The proceeds were used to fund capital expenditures during 1997,
and to repay all outstanding long-term indebtedness. As of
23
<PAGE> 26
December 31, 1999, the Company had $38.9 million of working capital (including
$20.0 million of cash on hand) and no debt outstanding after funding the equity
investment in Aquatica and $14.9 million of capital expenditures in 1998 and
$77.4 million of capital expenditures in 1999, which includes ERT's purchase of
26 blocks offshore, $31 million of construction costs for the Q4000 and $18.9
million for the acquisition of 56% interest in the Cal Dive Aker Dove (which was
subsequently sold in a sale/leaseback transaction). Subsequent to year end CDI's
cash on hand increased to $22 million at February 29, 2000 after funding ERT's
acquisition of six offshore blocks from EEX. Additionally, CDI has approximately
$40 million available under a Revolving Credit Agreement.
Operating Activities. Net cash provided by operating activities was $25.5
million in 1999, as compared to $35.7 million provided in 1998. This decrease is
primarily the result of decreased profitability of the Company and the level of
funding required to fund the increases in accounts receivable ($16.9 million
required in 1999 compared to $900,000 returned in 1998) which occurred primarily
as a result of the terms negotiated with EEX for the Cooper abandonment project.
Pursuant to those terms, $22 million was paid in January 2000. In addition,
depreciation and amortization increased as a result of natural gas and oil
properties acquisitions along with the write down of carrying value of three ERT
fields in 1999 discussed below.
The Company experienced an increase in the level of funding from accounts
payable and accrued liabilities of $15.7 million in 1999 compared to 1998. The
increase relates primarily to accruals with respect to the Q4000 construction
project and the EEX project.
Net cash provided by operating activities was $35.7 million in 1998, as
compared to $22.3 million provided in 1997. This increase was primarily the
result of increased profitability and a decline in the level of funding required
to fund accounts receivable increases ($5.8 million required in 1997 compared to
$900,000 returned in 1998). Other current assets increased $4.2 million at
December 31, 1998 as compared to December 31, 1997 due mainly to the purchases
of materials and supplies for the start up of the Full Field Development
program. In addition, depreciation and amortization increased as a result of
vessel and natural gas and oil properties acquisitions.
The Company experienced improved collections of its accounts receivable
during 1998 as compared to the prior year. Total accounts receivable decreased
$900,000 at December 31, 1998 as compared to December 31, 1997 while revenues
grew 39% in 1998 compared to 1997. The Company's average number of days to bill
and collect its trade receivables decreased by 10 days in 1998 as compared to
1997.
Investing Activities. Capital expenditures have consisted principally of
strategic asset acquisitions, the assembly of a fleet of DP vessels, including
the Witch Queen, Balmoral Sea, Uncle John, Sea Sorceress, Merlin and Cal Dive
Aker Dove, improvements to existing vessels and the acquisition of offshore
natural gas and oil properties. The Company has consistently targeted the year
2001 as the time when we will see a significant acceleration in Deepwater
demand. As a result, 1999 capital expenditures of $77.4 million were over five
times the prior year. This figure includes $31 million for the construction of
the Q4000, the acquisition of Hvide Marine's interest in Cal Dive Aker, CAHT I,
LLC, the Company which leases the Cal Dive Aker Dove (a newbuild DP anchor
handling and subsea construction vessel) ($18.9 million) as well as the purchase
of new engines for the Uncle John. ERT internally funded $17 million of capital
expenditures from the proceeds of the sale of offshore properties and the
repayment of deferred lease abandonment costs received in one acquisition.
During the first four months of 1999, in four separate transactions, ERT
acquired interests in 20 blocks in exchange for cash consideration, as well as
assumption of the pro rata share of the related decommissioning liabilities.
During 1998, ERT acquired net working interests in six blocks involving two
separate fields in exchange for cash as well as assumption of the pro rata share
of the related decommissioning liability. In connection with 1999 and 1998
offshore property acquisitions, ERT assumed net abandonment liabilities
estimated at approximately $19,500,000 and $3,432,000 respectively.
During the third quarter of 1999, ERT substantially completed its 1999 Well
Exploitation Program, which included five recompletions and which led to the
sale of its interest in three offshore blocks. It is an operating policy that
ERT will sell assets (offshore leases, platforms, compressors, etc.) when the
expected
24
<PAGE> 27
future revenue stream can be accelerated in a single transaction. Accordingly,
proceeds received from such transactions are recorded as revenue in the period
received. These sales were structured as Section 1031 "Like Kind" exchanges for
tax purposes. Accordingly, the cash received was restricted to use for
subsequent acquisitions of additional natural gas and oil properties which, as
discussed below, occurred in the first quarter of 2000. Since inception ERT has
acquired interests in 41 offshore leases, sold seven (two in 1997 and two in
1998), and taken one field full cycle to decommissioning. The well exploitation
work completed during the third quarter also enabled ERT to assess and write
down the carrying value of three ERT fields, including one where a third party
vendor damaged the reservoir formation. The net result of the sales and the 1999
Well Exploitation Program was to add approximately thirteen cents to 1999
diluted earnings per share.
During the first quarter 2000 ERT acquired interests in six offshore blocks
from EEX Corporation and agreed to operate the remaining EEX properties on the
Outer Continental Shelf (OCS). The acquired offshore blocks include working
interests from 40% to 75% in five platforms, one caisson and 13 wells currently
producing 23 mmcf per day (13 mmcf net). ERT exchanged cash of $4.9 million and
assumed EEX's prorated share of the abandonment obligation for the acquired
interests, and entered into a two-year contract to manage the remaining EEX
operated properties. EEX personnel who operated these properties also became ERT
employees. This acquisition was funded by restricted cash obtained from "Like
Kind" sales and accordingly, the gain for the sale was deferred for tax
purposes.
Since 1993, including the transactions closed subsequent to year end, the
Company has invested $43 million to acquire 47 offshore natural gas and oil
leases. The Company records the amount of cash paid together with the
abandonment liability assumed at the time such properties are acquired. Only the
cash paid at closing is reflected in the Company's statement of cash flows
together with bond and escrow deposits required in connection with these
purchases. The Minerals Management Service requires operators in the Gulf of
Mexico to post an areawide bond of $3 million. Beginning in 1998 the MMS allowed
the Company to utilize an insurance carrier to provide such bonding. The Company
has had, and anticipates having additional discussions with third parties
regarding possible acquisitions (including natural gas and oil properties and
vessels). However, the Company can give no assurance that any such transaction
can be completed.
In December, 1999, CAHT I entered into a sale-leaseback of the Cal Dive
Aker Dove. Cal Dive's portion of the proceeds received totaled $20 million and
resulted in a gain of $1.4 million which was deferred and is being amortized
over the ten year term of the lease. The lease, which is accounted for as an
operating lease, requires CAHT I to make quarterly payments of $988,000 and
contains a renewal option and options to purchase the vessel for amounts
approximating fair market value after 8 1/2 years of the lease term and at the
end of the lease term.
In February 1998, CDI purchased a significant minority equity interest in
Aquatica, Inc., a surface diving company for $5 million. Effective August 1,
1999, 696,000 shares of common stock of Cal Dive were issued for all of the
remaining common stock of Aquatica, Inc. This acquisition was accounted for as a
purchase with the acquisition price being allocated to the assets acquired and
liabilities assumed based upon their estimated fair values resulting in goodwill
of $12 million which is being amortized over twenty-five years on a straight-
line basis. Results of operations for Aquatica, Inc. are consolidated with those
of Cal Dive for periods subsequent to August 1, 1999.
The Company incurred $14.9 million of capital expenditures during 1998. In
January 1998, ERT acquired interests in six blocks involving two separate fields
from Sonat Exploration Company for cash and assumption of Sonat's pro rata share
of the related decommissioning liability. The remaining balance includes costs
associated with placing the Merlin in service and additions to the Sea Sorceress
in preparation for the Terra Nova project as well as the cost of new steel and
equipment added to the Witch Queen, Balmoral Sea and Cal Diver V during 1998
drydock inspections.
Financing Activities. The Company has financed seasonal operating
requirements and capital expenditures with internally generated funds,
borrowings under credit facilities, the sale of Common Stock and the
sale-leaseback transaction described above. The Revolving Credit Agreement, as
amended, currently provides for a $40.0 million revolving line of credit. The
Revolving Credit Agreement, which terminates in December 2000, is secured by
trade receivables and mortgages on the Company's vessels. The Revolving Credit
25
<PAGE> 28
Agreement prohibits the payment of dividends on the Company's capital stock and
contains only one financial covenant (a fixed charge coverage ratio) and a
limitation that debt not exceed $120 million. Interest on borrowings under the
Revolving Credit Agreement is equal to Prime with incentive pricing thereafter
pursuant to a formula based upon EBITDA (as defined therein). No borrowings were
outstanding at December 31, 1999. Letters of credit are also available under the
Revolving Credit Agreement which the Company typically uses if performance bonds
are required or, in certain cases, in lieu of purchasing U.S. Treasury Bonds in
conjunction with gas and oil property acquisitions.
The only financing activity in 1999 and 1998 represents the exercise of
employee stock options.
Capital Commitments. In connection with its business strategy, management
expects the Company to acquire or build additional vessels, acquire other
assets, as well as seek to buy additional natural gas and oil properties. In
July 1999, CDI's Board of Directors approved the construction of the Q4000, a
newbuild, ultra-deepwater multi-service vessel, at a total estimated cost of
$150 million. The Company recently received the "60 day letter" from the
Maritime Administration regarding the application for Title XI financing for
this semi-submersible vessel. The letter signifies that funding is available and
that CDI has satisfactorily answered MARAD's technical questions relative to the
vessel. If this financing transaction is approved, initial construction funding
will be drawn in the second quarter of 2000. We expect to submit a supplemental
appropriation of $20 million to $30 million to convert the Sea Sorceress to full
DP or purchase an existing DP vessel having similar Deepwater construction
features. Other than building, converting or buying DP vessels, management
believes existing cash balances, the net cash generated from operations and
available borrowing capacity under the Revolving Credit Agreement will be
adequate to meet funding requirements for the next year.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Not applicable because, at December 31, 1999, the Company was not engaged
in any transactions requiring disclosure under this item.
26
<PAGE> 29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants.................... 28
Consolidated Balance Sheets -- December 31, 1999 and 1998... 29
Consolidated Statements of Operations for the years ended
December 31, 1999, 1998 and 1997.......................... 30
Consolidated Statements of Shareholders' Equity for the
years ended December 31, 1999, 1998 and 1997.............. 31
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998 and 1997.......................... 32
Notes to Consolidated Financial Statements.................. 33
</TABLE>
27
<PAGE> 30
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Cal Dive International, Inc.:
We have audited the accompanying consolidated balance sheets of Cal Dive
International, Inc. (a Minnesota corporation) and subsidiaries as of December
31, 1999 and 1998, and the related consolidated statements of operations,
shareholders' equity and cash flows for the three years in the period ended
December 31, 1999. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Cal Dive
International, Inc., and subsidiaries as of December 31, 1999 and 1998, and the
results of their operations and their cash flows for the three years in the
period ended December 31, 1999, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 17, 2000
28
<PAGE> 31
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
(IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1999 1998
-------- --------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 11,310 $ 32,380
Restricted Cash........................................... 8,686 463
Accounts receivable --
Trade, net of revenue allowance on gross amounts billed
of $1,789 and $1,335.................................. 48,191 20,350
Unbilled revenue....................................... 3,430 10,703
Other current assets...................................... 16,327 9,190
-------- --------
Total current assets.............................. 87,944 73,086
-------- --------
Property and equipment...................................... 180,519 107,421
Less -- Accumulated depreciation.......................... (45,862) (28,262)
-------- --------
134,657 79,159
Other assets:
Investment in Aquatica, Inc. ............................. -- 7,656
Goodwill.................................................. 13,792 --
Other assets, net......................................... 7,329 4,334
-------- --------
$243,722 $164,235
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 31,834 $ 15,949
Accrued liabilities....................................... 17,223 10,020
Income taxes payable...................................... -- 1,201
-------- --------
Total current liabilities......................... 49,057 27,170
-------- --------
Long-term debt.............................................. -- --
Deferred income taxes....................................... 16,837 13,539
Decommissioning liabilities................................. 26,956 9,883
Commitments and contingencies
Shareholders' equity:
Common stock, no par, 60,000 shares authorized, 22,395 and
21,402 shares issued................................... 73,311 52,981
Retained earnings......................................... 81,312 64,413
Treasury stock, 6,820 shares, at cost..................... (3,751) (3,751)
-------- --------
Total shareholders' equity........................ 150,872 113,643
-------- --------
$243,722 $164,235
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
29
<PAGE> 32
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Net revenues:
Subsea and salvage........................................ $128,435 $139,310 $ 92,860
Natural gas and oil production............................ 32,519 12,577 16,526
-------- -------- --------
160,954 151,887 109,386
Cost of sales:
Subsea and salvage........................................ 103,113 93,607 67,538
Natural gas and oil production............................ 20,590 9,071 8,163
-------- -------- --------
Gross profit........................................... 37,251 49,209 33,685
Selling and administrative expenses......................... 13,227 15,801 11,196
-------- -------- --------
Income from operations...................................... 24,024 33,408 22,489
Equity in earnings of Aquatica, Inc. ..................... 600 2,633 --
Net interest (income) expense and other................... (849) (1,103) 208
-------- -------- --------
Income before income taxes.................................. 25,473 37,144 22,281
Provision for income taxes................................ 8,465 13,019 7,799
Minority Interest......................................... 109 -- --
-------- -------- --------
Net income........................................ $ 16,899 $ 24,125 $ 14,482
======== ======== ========
Net income per share:
Basic..................................................... $ 1.13 $ 1.66 $ 1.12
Diluted................................................... 1.10 1.61 1.09
======== ======== ========
Weighted average common shares outstanding:
Basic..................................................... 15,008 14,549 12,883
Diluted................................................... 15,327 14,964 13,313
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
30
<PAGE> 33
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK TREASURY STOCK TOTAL
---------------- RETAINED ---------------- SHAREHOLDERS'
SHARES AMOUNT EARNINGS SHARES AMOUNT EQUITY
------ ------- -------- ------ ------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1996......... 18,448 $ 9,093 $25,806 (7,349) $(4,055) $ 30,844
Net income......................... -- -- 14,482 -- -- 14,482
Activity in company stock plans.... 22 327 -- -- -- 327
Sale of treasury stock, net........ -- 4,055 -- 529 304 4,359
Sale of common stock, net.......... 2,875 39,357 -- -- -- 39,357
------ ------- ------- ------ ------- --------
Balance, December 31, 1997......... 21,345 52,832 40,288 (6,820) (3,751) 89,369
Net income......................... -- -- 24,125 -- -- 24,125
Activity in company stock plans,
net.............................. 57 149 -- -- -- 149
------ ------- ------- ------ ------- --------
Balance, December 31, 1998......... 21,402 52,981 64,413 (6,820) (3,751) 113,643
Net income......................... -- -- 16,899 -- -- 16,899
Activity in company stock plans,
net.............................. 297 4,174 -- 4,174
Acquisition of Aquatica, Inc. ..... 696 16,156 -- -- -- 16,156
------ ------- ------- ------ ------- --------
Balance, December 31, 1999......... 22,395 $73,311 $81,312 (6,820) $(3,751) $150,872
====== ======= ======= ====== ======= ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
31
<PAGE> 34
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income................................................ $ 16,899 $ 24,125 $ 14,482
Adjustments to reconcile net income to net cash provided
by operating activities --
Depreciation and amortization.......................... 20,615 9,563 7,512
Deferred income taxes.................................. 4,298 4,469 3,789
Equity in earnings of Aquatica, Inc. .................. (600) (2,633) --
Gain on sale of gas and oil properties................. (8,454) (585) (464)
Changes in operating assets and liabilities:
Accounts receivable, net............................. (16,918) 937 (5,777)
Other current assets................................. ( 6,468) (3,919) (2,653)
Accounts payable and accrued liabilities............. 21,217 5,536 4,766
Income taxes payable, net............................ (430) 599 736
Other noncurrent, net................................ (4,660) (2,395) (97)
-------- -------- --------
Net cash provided by operating activities......... 25,499 35,697 22,294
-------- -------- --------
Cash flows from investing activities:
Capital expenditures...................................... (77,447) (14,886) (28,936)
Restricted Cash........................................... (8,222) (463) --
Investment in Aquatica, Inc. ............................. 442 (5,023) --
Prepayment of Deferred Lease Abandonment Costs............ 7,750 --
Deposits restricted for salvage operations................ (66) 3,262 (436)
Proceeds from sales of property........................... 28,931 619 1,084
-------- -------- --------
Net cash used in investing activities............. (48,612) (16,491) (28,288)
-------- -------- --------
Cash flows from financing activities:
Exercise of stock warrants and options, net............... 2,043 149 99
Sale of common stock, net of transaction costs............ -- -- 39,357
Sale of treasury stock, net of transaction costs.......... -- -- 4,359
Borrowings under term loan facility, net.................. -- -- 6,700
Repayments of long-term debt.............................. -- -- (31,700)
-------- -------- --------
Net cash provided by financing activities......... 2,043 149 18,815
-------- -------- --------
Net increase (decrease) in cash and cash equivalents........ (21,070) 19,355 12,821
Cash and cash equivalents:
Balance, beginning of year................................ 32,380 13,025 204
-------- -------- --------
Balance, end of year...................................... $ 11,310 $ 32,380 $ 13,025
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
32
<PAGE> 35
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION:
Cal Dive International, Inc. (Cal Dive, CDI or the Company), headquartered
in Houston, Texas, owns, staffs and operates fourteen marine construction
vessels and a derrick barge in the Gulf of Mexico. The Company provides a full
range of services to offshore oil and gas exploration and production and
pipeline companies, including underwater construction, maintenance and repair of
pipelines and platforms, and salvage operations. Diving and vessel support
services in the shallow water market are provided by Aquatica, Inc., a
wholly-owned subsidiary based in Lafayette, Louisiana.
In September 1992, Cal Dive formed a wholly owned subsidiary, Energy
Resource Technology, Inc. (ERT), to purchase producing offshore oil and gas
properties which are in the later stages of their economic lives. ERT is a fully
bonded offshore operator and, in conjunction with the acquisition of properties,
assumes the responsibility to decommission the property in full compliance with
all governmental regulations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of
the Company and its subsidiaries. All significant intercompany accounts and
transactions have been eliminated.
Goodwill
Goodwill is amortized on the straight-line method over its estimates useful
life of 25 years. The Company continually evaluates whether subsequent events or
circumstances have occurred that indicates the remaining useful life of goodwill
may warrant revision or that the remaining balance of goodwill may not be
recoverable. Management believes that there have been no events or circumstances
which warrant revision to the remaining useful life or which affect
recoverability of goodwill.
Property and Equipment
Property and equipment are recorded at cost. Depreciation is provided
primarily on the straight-line method over the estimated useful lives of the
assets.
All of the Company's interests in natural gas and oil properties are
located offshore in United States waters. The Company follows the successful
efforts method of accounting for its interests in natural gas and oil
properties. Under the successful efforts method, only the costs of successful
wells and leases containing productive reserves are capitalized.
ERT offshore property acquisitions are recorded at the value exchanged at
closing together with an estimate of its proportionate share of the
decommissioning liability assumed in the purchase based upon its working
interest ownership percentage. In estimating the decommissioning liability
assumed in offshore property acquisitions, the Company performs detailed
estimating procedures, including engineering studies. All capitalized costs are
amortized on a unit-of-production basis (UOP) based on the estimated remaining
oil and gas reserves. Properties are periodically assessed for impairment in
value, with any impairment charged to expense.
33
<PAGE> 36
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is a summary of the components of property and equipment
(dollars in thousands):
<TABLE>
<CAPTION>
ESTIMATED
USEFUL LIFE 1999 1998
----------- -------- --------
<S> <C> <C> <C>
Vessels.............................................. 15 $ 85,397 $ 72,220
Offshore leases and equipment........................ UOP 49,037 22,530
Construction in Progress............................. N/A 31,341 --
Machinery, equipment and leasehold improvements...... 5 14,744 12,671
-------- --------
Total property and equipment............... $180,519 $107,421
======== ========
</TABLE>
In July 1999, the CDI Board of Directors approved the construction of the
Q4000, a newbuild, ultra-deepwater multi-purpose vessel, for a total estimated
cost of $150 million. Amounts incurred on this project through the end of 1999
are included in Construction in Progress.
The cost of repairs and maintenance of vessels and equipment is charged to
operations as incurred, while the cost of improvements is capitalized. Total
repair and maintenance charges were $6,031,000, $8,264,000 and $6,771,000 for
the years ended December 31, 1999, 1998 and 1997, respectively.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Earnings Per Share
The Company computes and presents earning per share in accordance with
Statement of Financial Accounting Standard No. 128, "Earnings Per Share". SFAS
128 requires the presentation of "basic" EPS and "diluted" EPS on the face of
the statement of operations. Basic EPS is computed by dividing the net income
available to common shareholders by the weighted-average shares of outstanding
common stock. The calculation of diluted EPS is similar to basic EPS except that
the denominator includes dilutive common stock equivalents, which were stock
options, less the number of treasury shares assumed to be purchased from the
proceeds from the exercise of stock options.
Revenue Recognition
The Company earns the majority of its service revenues during the summer
and fall months. Revenues are derived from billings under contracts (which are
typically of short duration) that provide for either lump-sum turnkey charges or
specific time, material and equipment charges which are billed in accordance
with the terms of such contracts. The Company recognizes revenue as it is earned
at estimated collectible amounts. Revenue on significant turnkey contracts is
recognized on the percentage-of-completion method based on the ratio of costs
incurred to total estimated costs at completion. Contract price and cost
estimates are reviewed periodically as work progresses and adjustments are
reflected in the period in which such estimates are revised. Provisions for
estimated losses on such contracts are made in the period such losses are
determined. Unbilled revenue represents revenue attributable to work completed
prior to year-end which has not yet been invoiced. All amounts included in
unbilled revenue at December 31, 1999 are expected to be billed and collected
within one year.
34
<PAGE> 37
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revenue Allowance on Gross Amounts Billed
The Company bills for work performed in accordance with the terms of the
applicable contract. The gross amount of revenue billed will include not only
the billing for the original amount quoted for a project but also include
billings for services provided which the Company believes are outside the scope
of the original quote. The Company establishes a revenue allowance for these
additional billings based on its collections history if conditions warrant such
a reserve.
Major Customers and Concentration of Credit Risk
The market for the Company's services is the offshore oil and gas industry.
Oil and gas companies make capital expenditures on exploration, drilling and
production operations offshore, the level of which is generally dependent on the
prevailing view of the future oil and gas prices, which have been characterized
by significant volatility in recent years. The Company's customers consist
primarily of major, well-established oil and pipeline companies and independent
oil and gas producers. The Company performs ongoing credit evaluations of its
customers and provides allowances for probable credit losses when necessary.
The percent of consolidated revenue of major customers was as follows:
1999 -- EEX Corporation (13%); 1998 -- Chevron USA (11%); and 1997 -- Shell Oil
Co. (11%) and -- J. Ray McDermott, S.A. (19%).
Income Taxes
Deferred taxes are recognized for revenues and expenses reported in
different years for financial statement purposes and income tax purposes in
accordance with SFAS No. 109, "Accounting for Income Taxes." The statement
requires, among other things, the use of the liability method of computing
deferred income taxes. The liability method is based on the amount of current
and future taxes payable using tax rates and laws in effect at the balance sheet
date.
Deferred Drydock Charges
Effective January 1, 1998, the Company changed its method of accounting for
regulatory (U.S. Coast Guard, American Bureau of Shipping and Det Norske
Veritas) related drydock inspection and certification expenditures. This change
was made due to the significant changes in the composition of the Company's
fleet which has been expanded to include more sophisticated dynamically
positioned vessels that are capable of working in the Deepwater Gulf of Mexico,
a key to Cal Dive's operating strategy. The Company previously expensed
inspection and certification costs as incurred; however, effective January 1,
1998, such expenditures are being capitalized and amortized over the 30-month
period between regulatory mandated drydock inspections and certification. This
predominant industry practice provides better matching of expenses with the
period benefitted (i.e., certification to operate the vessel for a 30-month
period between required drydock inspections and to meet bonding and insurance
coverage requirements). This change had a $765,000 positive impact on net
income, or $0.05 per share, in the Company's 1998 consolidated financial
statements.
Statement of Cash Flow Information
The Company defines cash and cash equivalents as cash and all highly liquid
financial instruments with original maturities of less than three months. During
the years ended December 31, 1999, 1998 and 1997, the Company's cash payments
for interest expense were approximately $-0-, $-0- and $1,033,000 respectively,
and cash payments for federal income taxes were approximately $4,075,000,
$7,650,000 and $3,200,000 respectively.
35
<PAGE> 38
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Reclassifications
Certain reclassifications were made to previously reported amounts in the
consolidated financial statements and notes to make them consistent with the
current presentation format.
3. ACQUISITION OF AQUATICA, INC.:
In February 1998, CDI purchased a significant minority equity interest in
Aquatica, Inc., a surface diving company. CDI accounted for this investment on
the equity basis of accounting for financial reporting purposes. The related
Shareholder Agreement provided that the remaining shares of Aquatica, Inc. could
be converted into Cal Dive shares based on a formula which, among other things,
values their shares of Aquatica, Inc. and must be accretive to Cal Dive
shareholders. Effective August 1, 1999, 696,000 shares of common stock of Cal
Dive were issued for all of the remaining common stock of Aquatica, Inc.
pursuant to these terms. This acquisition was accounted for as a purchase with
the acquisition price of $16.2 million being allocated to the assets acquired
and liabilities assumed based upon their estimated fair values. The fair value
of tangible assets acquired and liabilities assumed was $6.4 million and $2.2
million, respectively. The balance of the purchase price ($12 million) was
recorded as excess of cost over net assets acquired (goodwill). Accumulated
amortization as of December 31,1999 was $300,000. Results of operations for
Aquatica, Inc. are consolidated with those of Cal Dive for periods subsequent to
August 1, 1999.
4. OFFSHORE PROPERTY TRANSACTIONS:
During the first four months of 1999, in four separate transactions, ERT
acquired interests in 20 blocks in exchange for cash consideration, as well as
assumption of the pro rata share of the related decommissioning liabilities.
During 1997, ERT acquired net working interests of 50 percent to 100 percent in
3 offshore blocks and in 1998, interests in six blocks involving two separate
fields in exchange for cash as well as assumption of the pro rata share of the
related decommissioning liability. In connection with 1999, 1998 and 1997
offshore property acquisitions, ERT assumed net abandonment liabilities
estimated at approximately $19,500,000, $3,432,000 and $1,351,000 respectively.
ERT production activities are regulated by the federal government and
require significant third-party involvement, such as refinery processing and
pipeline transportation. The Company records revenue from its offshore
properties net of royalties paid to the Minerals Management Service ("MMS").
Royalty fees paid totaled approximately $4,017,000, $2,031,000 and $3,018,000
for the years ended 1999, 1998 and 1997, respectively. In accordance with
federal regulations that require operators in the Gulf of Mexico to post an
areawide bond of $3,000,000,the MMS has allowed the Company to fulfill such
bonding requirements through an insurance policy.
During the third quarter of 1999, ERT substantially completed its 1999 Well
Exploitation Program, which included five recompletions and which led to the
sale of its interest in certain offshore blocks. It is an operating policy that
ERT will sell assets (offshore leases, platforms, compressors, etc.) when the
expected future revenue stream can be accelerated in a single transaction.
Accordingly, proceeds received from such transactions are recorded as revenue in
the period received. These sales were structured as Section 1031 "Like Kind"
exchanges for tax purposes. Accordingly, the cash received was restricted to use
for subsequent acquisitions of additional natural gas and oil properties. Since
inception ERT has acquired interests in 41 offshore leases, sold seven (two in
1997 and two in 1998), and taken one field full cycle to decommissioning. The
well exploitation work completed during the third quarter also enabled ERT to
assess and write down the carrying value of three ERT fields, including one
where a third party vendor damaged the reservoir formation. The net result of
the sales and the 1999 Well Exploitation Program was to add approximately
thirteen cents to 1999 diluted earnings per share.
36
<PAGE> 39
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. ACCRUED LIABILITIES:
Accrued liabilities consisted of the following (in thousands):
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
Accrued payroll and related benefits........................ $ 6,606 $ 5,198
Workers' compensation claims................................ 497 1,919
Workers' compensation claims to be reimbursed............... 6,241 867
Other....................................................... 3,879 2,036
------- -------
Total accrued liabilities......................... $17,223 $10,020
======= =======
</TABLE>
6. REVOLVING CREDIT FACILITY:
Since April 1997, the Company has had a revolving credit facility of $40
million available. Interest rates vary from .5% above prime and 2% above the
Eurodollar base rate to prime and 1.25 to 2.50 percent above Eurodollar based on
specific provisions set forth in the loan agreement. Covenant restrictions
include only a fixed charge ratio. The Company was in compliance with these debt
covenants at December 31, 1999.
7. FEDERAL INCOME TAXES:
Federal income taxes have been provided based on the statutory rate of 35
percent in 1999 and 35 percent in 1997 and 1998 adjusted for items which are
allowed as deductions for federal income tax reporting purposes, but not for
book purposes. The primary differences between the statutory rate and the
Company's effective rate are as follows:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Statutory rate.............................................. 35% 35% 35%
Research and development tax credits........................ (3) (1) --
Other....................................................... 1 1 --
-- -- --
Effective rate.................................... 33% 35% 35%
== == ==
</TABLE>
Components of the provision for income taxes reflected in the statements of
operations consist of the following (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
------ ------- ------
<S> <C> <C> <C>
Current................................................... $4,167 $ 8,550 $4,010
Deferred.................................................. 4,298 4,469 3,789
------ ------- ------
$8,465 $13,019 $7,799
====== ======= ======
</TABLE>
Deferred income taxes result from those transactions which affect financial
and taxable income in different years. The nature of these transactions and the
income tax effect of each as of December 31, 1999 and 1998, is as follows (in
thousands):
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
Deferred tax liabilities --
Depreciation.............................................. $16,837 $13,539
Deferred tax assets --
Reserves, accrued liabilities and other................... (532) (416)
------- -------
Net deferred tax liability........................ $16,305 $13,123
======= =======
</TABLE>
37
<PAGE> 40
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. COMMITMENTS AND CONTINGENCIES:
Lease Commitments
During 1999, CDI acquired Hvide Marine's interest in Cal Dive Aker CAHT I,
LLC (CAHT I), the company which owned the Cal Dive Aker Dove (a newbuild DP
anchor handling and subsea construction vessel which commenced operations in
September 1999) for a total of $18.9 million. CDI effectively owns 56% of CAHT I
and accordingly results of operations of this company are consolidated in the
accompanying financial statements with Aker's share being reflected as minority
interest.
In December, 1999, CAHT I entered into a sale-leaseback of the Cal Dive
Aker Dove. Cal Dive's portion of the proceeds received totaled $20 million and
resulted in a gain of $1.4 million which was deferred and is being amortized
over the ten year term of the lease. The lease, which is accounted for as an
operating lease, requires CAHTI to make quarterly payments of $988,000 and
contains a renewal option and options to purchase the vessel for amounts
approximating fair market value after 8 1/2 years of the lease term and at the
end of the lease term.
The Company occupies several facilities under noncancelable operating
leases, with the more significant leases expiring in the years 2004 and 2007.
Future minimum rentals under these leases are $3.4 million at December 31, 1999
with $579,000 due in 2000, $599,000 in 2001, $622,000 in 2002, $676,000 in 2003,
$516,000 in 2004 and the balance thereafter. Total rental expense under these
operating leases was $673,000, $601,000 and $376,000 for the years ended
December 31, 1999, 1998 and 1997, respectively.
Insurance and Litigation
The Company carries hull protection on vessels, indemnity insurance and a
general umbrella policy. All onshore employees are covered by workers'
compensation, and all offshore employees, including divers and tenders, are
covered by Jones Act employee coverage, the maritime equivalent of workers'
compensation. The Company is exposed to deductible limits on its insurance
policies, which vary from $5,000 to a maximum of $100,000 per accident
occurrence. Effective August 1, 1992, the Company adopted a self-insured (within
specified limits) medical and health benefits program for its employees whereby
the Company is exposed to a maximum of $15,000 per claim.
In 1998, CDI entered into a subcontract with Seacore Marine Contractors
Limited (Seacore) to provide a vessel (the Sea Sorceress) for the excavation of
glory holes on the Terra Nova Project in the North Atlantic ocean. Seacore was
in turn contracted by Coflexip Stena Offshore. Due to unforeseen difficulties
with respect to the sea states and soil conditions, Coflexip chose to suspend
glory hole dredging for the 1998 season. Subsequently, Coflexip formally
terminated the contract with Seacore and issued a call against a performance
bond provided by Seacore. CDI has provided Seacore a performance bond of $5
million with respect to the subcontract of the Sea Sorceress although no call
has been made on this bond. Seacore and CDI believe the contract was wrongfully
terminated and are vigorously defending this claim in arbitration.
The Company incurs workers' compensation claims in the normal course of
business, which management believes are covered by insurance. The Company, its
insurers and legal counsel analyze each claim for potential exposure and
estimate the ultimate liability of each claim. Amounts accrued and receivable
from insurance companies, above the applicable deductible limits, are reflected
in other current assets in the consolidated balance sheet. Such amounts were
$6,241,000 and $867,000 as of December 31, 1999 and 1998, respectively. See
related accrued liabilities at Note 5. The Company has not incurred any
significant losses as a result of claims denied by its insurance carriers. In
addition, the Company from time to time incurs other claims, such as contract
disputes, in the normal course of business. In the opinion of management, the
ultimate liability to the Company, if any, which may result from the claims
discussed above will not materially affect the Company's consolidated financial
position, results of operations or net cash flows.
38
<PAGE> 41
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. EMPLOYEE BENEFIT PLANS:
Defined Contribution Plan
The Company sponsors a defined contribution 401(k) retirement plan covering
substantially all of its employees. The Company's contributions and cost are
determined annually as 50 percent of each employee's contribution up to 5
percent of the employee's salary. The Company's costs related to this plan
totaled $375,000, $431,000 and $305,000 for the years ended December 31, 1999,
1998 and 1997, respectively.
Stock-Based Compensation Plans
During 1995, the Board of Directors and shareholders approved the 1995
Long-Term Incentive Plan (the Incentive Plan). Under the Incentive Plan, a
maximum of 10% of the total shares of Common Stock issued and outstanding may be
granted to key executives and selected employees who are likely to make a
significant positive impact on the reported net income of the Company. The
Incentive Plan is administered by a committee which determines, subject to
approval of the Compensation Committee of the Board of Directors, the type of
award to be made to each participant and sets forth in the related award
agreement the terms, conditions and limitations applicable to each award. The
committee may grant stock options, stock appreciation rights, or stock and cash
awards. Options granted to employees under the Incentive Plan vest 20% per year
for a five year period, have a maximum exercise life of five years and, subject
to certain exceptions, are not transferable.
Effective May 12, 1998, the Company adopted a qualified, non-compensatory
Employee Stock Purchase Plan ("ESPP"), which allows employees to acquire shares
of common stock through payroll deductions over a six month period. The purchase
price is equal to 85 percent of the fair market value of the common stock on
either the first or last day of the subscription period, whichever is lower.
Purchases under the plan are limited to 10 percent of an employee's base salary.
Under this plan 11,238 and 13,937 shares of common stock were purchased in the
open market at a weighted average share price of $24.38 and $21.25 during 1999
and 1998, respectively.
The Incentive Plan and ESPP are accounted for using APB Opinion No. 25, and
therefore no compensation expense is recorded. If SFAS Statement No. 123 had
been used for the accounting of these plans, the Company's pro forma net income
for 1999, 1998 and 1997 would have been $16,218,000, $23,735,000 and $14,023,000
respectively, and the Company's pro forma diluted earnings per share would have
been $1.06, $1.59 and $1.07 respectively. These pro forma results exclude
consideration of options granted prior to January 1, 1995, and therefore may not
be representative of that to be expected in future years.
All of the options outstanding at December 31, 1999, have exercise prices
as follows: 184,500 shares at $4.50, 116,054 at $7.90, 387,000 shares at $9.50,
82,000 shares at $13.00, 84,770 shares at $20.56 and 124,280 shares ranging from
$14.00 to $32.00 and a weighted average remaining contractual life of 2.49
years.
The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option pricing model with the following weighted average
assumptions used: expected dividend yields of 0 percent; expected lives of five
years risk-free interest rate assumed to be 5.5 percent in 1997, 5.0 percent in
1998 and 5.5 percent in 1999 and expected volatility to be 36 percent in 1997
and 59 percent in 1998 and 1999. The fair value of shares issued under the ESPP
was based on the 15% discount received by the employees.
39
<PAGE> 42
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Options outstanding are as follows:
<TABLE>
<CAPTION>
1999 1998 1997
-------------------- -------------------- ------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- -------- --------- -------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Options outstanding,
beginning of year....... 1,044,600 $ 9.40 994,500 $8.66 544,500 $4.50
Granted................... 238,969 12.07 325,850 23.55 540,000 12.17
Exercised................. (292,965) 6.84 (56,750) 5.03 (22,000) 4.50
Terminated................ ( 12,000) 4.50 (219,000) 28.24 (68,000) 4.50
--------- ------ --------- ----- ------- -----
Options outstanding,
December 31............. 978,604 $11.18 1,044,600 $9.40 994,500 $8.66
Options exercisable,
December 31............. 247,744 $ 8.59 222,950 $6.50 199,604 $4.50
========= ====== ========= ===== ======= =====
</TABLE>
Options granted in 1999 include 143,639 shares issued in connection with
the August 1, 1999 acquisition of Aquatica, Inc., which provided for conversion
of Aquatica employee stock options into Cal Dive stock options at the same ratio
which Aquatica common shares were converted into Cal Dive common shares. Options
granted and options terminated under the Incentive Plan for 1998 include options
which were repriced on November 6, 1998. The options which were repriced were
originally granted between August 25, 1997 and May 11, 1998 with original
exercise prices between $28.38 and $37.25. Options for 165,000 shares were
cancelled on November 6, 1998 and a proportionately reduced number of shares
(100,850) were reissued at an exercise price of $20.56 per share with a new five
year vesting period.
10. COMMON STOCK:
The Company's amended and restated Articles of Incorporation provide for
authorized Common Stock of 60,000,000 shares with no par value per share.
On April 11, 1997, Coflexip purchased approximately 3,700,000 shares of the
Company's stock, consisting of approximately 2.1 million shares sold by
management of the Company and 1.1 million shares sold by First Reserve Funds at
a price of $9.46 per share. Coflexip agreed to accept approximately 500,000
shares of the Company's Common Stock as payment for two ROVs at published retail
prices as part of this transaction. The Company also entered into a joint
venture with Coflexip (Quantum Offshore Contractors, L.L.C.) designed to target
larger EPIC contracts in the Gulf of Mexico. Such contracts did not develop and
accordingly in December 1999 this venture was dissolved in favor of a new
business arrangement which will enable the parties to consult and cooperate with
one another as they see fit on a project-by-project basis.
In conjunction with the Coflexip transaction, the Company entered into a
new Shareholders Agreement. The new Shareholders Agreement provides that, except
in limited circumstances (including issuance of securities under stock option
plans or in conjunction with acquisitions), the Company shall provide preemptive
rights to acquire the Company's securities to each of Coflexip and the Executive
Directors. The Shareholders Agreement also provides that the Company will not
enter into an agreement (i) to sell the Company, (ii) to retain an advisor to
sell the Company or (iii) to pursue any acquisition in excess of 50% of the
Company's market capitalization without first notifying Coflexip in writing and
providing Coflexip the opportunity to consummate an acquisition on terms
substantially equivalent to any proposal.
The Company completed an initial public offering of common stock on July 7,
1997, with the sale of 4.1 million shares at $15 per share. Of the 4.1 million
shares, 2,875,000 shares were sold by the Company and
40
<PAGE> 43
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1,265,000 shares were sold by First Reserve Funds. Net proceeds to the Company
of approximately $39.4 million were used to retire all of its then outstanding
long-term indebtedness of $20 million.
In May 1998, the Company completed a secondary offering of 2,867,070 shares
of common stock at $33.50 per share on behalf of certain selling shareholders.
The Company received no proceeds from the offering.
11. BUSINESS SEGMENT INFORMATION (IN THOUSANDS):
The following summarizes certain financial data by business segment:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Revenues --
Subsea and salvage................................. $128,435 $139,310 $ 92,860
Natural gas and oil production..................... 32,519 12,577 16,526
-------- -------- --------
Total...................................... $160,954 $151,887 $109,386
======== ======== ========
Income from operations --
Subsea and salvage................................. $ 15,817 $ 31,440 $ 16,411
Natural gas and oil production..................... 8,207 1,968 6,078
-------- -------- --------
Total...................................... $ 24,024 $ 33,408 $ 22,489
======== ======== ========
Net interest (income) expense and other --
Subsea and salvage................................. $ (264) $ (705) $ 379
Natural gas and oil production..................... (585) (398) (171)
-------- -------- --------
Total...................................... $ (849) $ (1,103) $ 208
======== ======== ========
Provision for income taxes --
Subsea and salvage................................. $ 5,431 $ 12,195 $ 5,614
Natural gas and oil production..................... 3,034 824 2,185
-------- -------- --------
Total...................................... $ 8,465 $ 13,019 $ 7,799
======== ======== ========
Identifiable assets --
Subsea and salvage................................. $197,570 $142,629 $107,420
Natural gas and oil production..................... 46,152 21,606 18,180
-------- -------- --------
Total...................................... $243,722 $164,235 $125,600
======== ======== ========
Capital expenditures --
Subsea and salvage................................. $ 60,662 $ 10,923 $ 26,984
Natural gas and oil production..................... 16,785 3,963 1,952
-------- -------- --------
Total...................................... $ 77,447 $ 14,886 $ 28,936
======== ======== ========
Depreciation and amortization --
Subsea and salvage................................. $ 9,459 $ 6,966 $ 4,000
Natural gas and oil production..................... 11,156 2,597 3,512
-------- -------- --------
Total...................................... $ 20,615 $ 9,563 $ 7,512
======== ======== ========
</TABLE>
41
<PAGE> 44
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED):
The following information regarding the Company's oil and gas producing
activities is presented pursuant to SFAS No. 69, "Disclosures About Oil and Gas
Producing Activities" (in thousands).
Capitalized Costs
Aggregate amounts of capitalized costs relating to the Company's oil and
gas producing activities and the aggregate amount of related accumulated
depletion, depreciation and amortization as of the dates indicated are presented
below. The Company has no capitalized costs related to unproved properties.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------
1999 1998
-------- -------
<S> <C> <C>
Proved properties being amortized........................... $ 49,037 $22,530
Less -- Accumulated depletion, depreciation and
amortization.............................................. (19,530) (9,082)
-------- -------
Net capitalized costs............................. $ 29,507 $13,448
======== =======
</TABLE>
Included in capitalized costs is the Company's estimate of its
proportionate share of decommissioning liabilities assumed relating to these
properties. As of December 31, 1999 and 1998, such liabilities totaled $27.0
million and $9.9 million, respectively, and are also reflected as
decommissioning liabilities in the accompanying consolidated balance sheet.
Costs Incurred in Oil and Gas Producing Activities
The following table reflects the costs incurred in oil and gas property
acquisition and development activities during the dates indicated:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
1999 1998 1997
------- ------ ------
<S> <C> <C> <C>
Proved property acquisition costs......................... $22,610 $5,416 $2,687
Development costs......................................... 5,002 2,281 385
------- ------ ------
Total costs incurred............................ $27,612 $7,697 $3,072
======= ====== ======
</TABLE>
Results of Operations For Oil and Gas Producing Activities
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Revenues................................................ $32,519 $12,577 $16,526
Production (lifting) costs.............................. 9,433 6,820 4,651
Depreciation, depletion and amortization................ 11,156 2,597 3,512
------- ------- -------
Pretax income from producing activities................. 11,930 3,160 8,363
Income tax expenses..................................... 3,034 1,106 2,927
------- ------- -------
Results of oil and gas producing activities............. $ 8,896 $ 2,054 $ 5,436
======= ======= =======
</TABLE>
Estimated Quantities of Proved Oil and Gas Reserves
Proved oil and gas reserve quantities are based on estimates prepared by
Company engineers in accordance with guidelines established by the Securities
and Exchange Commission. The Company's estimates of reserves at December 31,
1999, have been reviewed by Miller and Lents, Ltd., independent petroleum
engineers. All of the Company's reserves are located in the United States.
Proved reserves cannot
42
<PAGE> 45
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
be measured exactly because the estimation of reserves involves numerous
judgmental determinations. Accordingly, reserve estimates must be continually
revised as a result of new information obtained from drilling and production
history, new geological and geophysical data and changes in economic conditions.
As of December 31, 1997, 4,500 Bbls. of oil and 6,325,700 Mcf. of gas of
the Company's proved reserves were undeveloped. As of December 31, 1998, 400
Bbls. of oil and 1,153,300 Mcf. of gas were undeveloped. As of December 31,
1999, 337,500 Bbls. of oil and 284,800 Mcf. of gas were undeveloped.
<TABLE>
<CAPTION>
OIL GAS
RESERVE QUANTITY INFORMATION (MBBLS.) (MMCF.)
- ---------------------------- -------- -------
<S> <C> <C>
Total proved reserves at December 31, 1996.................. 124 24,596
Revisions of previous estimates........................... (21) 1,831
Production................................................ (51) (5,385)
Purchases of reserves in place............................ 149 2,115
Sales of reserves in place................................ (1) (912)
----- ------
Total proved reserves at December 31, 1997.................. 200 22,245
Revisions of previous estimates........................... (123) (1,706)
Production................................................ (67) (4,535)
Purchase of reserves in place............................. 60 6,631
Sales of reserves in place................................ -- (201)
----- ------
Total proved reserves at December 31, 1998.................. 70 22,434
Revisions of previous estimates........................... 1,091 (2,392)
Production................................................ (339) (6,819)
Purchase of reserves in place............................. 888 17,218
Sales of reserves in place................................ (8) (5,060)
----- ------
Total proved reserves at December 31, 1999.................. 1,702 25,381
===== ======
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
The following table reflects the standardized measure of discounted future
net cash flows relating to the Company's interest in proved oil and gas reserves
as of December 31:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Future cash inflows.................................. $101,686 $ 47,691 $ 59,819
Future costs --
Production...................................... (30,550) (17,412) (23,675)
Development and abandonment..................... (30,303) (11,232) (6,917)
-------- -------- --------
Future net cash flows before income taxes............ 40,833 19,047 29,227
Future income taxes................................ (16,191) (6,477) (7,927)
-------- -------- --------
Future net cash flows................................ 24,642 12,570 21,300
Discount at 10% annual rate........................ (1,799) (2,414) (1,540)
-------- -------- --------
Standardized measure of discounted future net cash
flows.............................................. $ 22,843 $ 10,156 $ 19,760
======== ======== ========
</TABLE>
43
<PAGE> 46
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Changes in Standardized Measure of Discounted Future Net Cash Flows
Principal changes in the standardized measure of discounted future net cash
flows attributable to the Company's proved oil and gas reserves are as follows:
<TABLE>
<CAPTION>
1999 1998 1997
-------- ------- --------
<S> <C> <C> <C>
Standardized measure, beginning of year............... $ 10,156 $19,760 $ 33,805
Sales, net of production costs........................ (23,086) (5,757) (11,441)
Net change in prices, net of production costs......... 15,968 (4,573) (17,707)
Changes in future development costs................... (1,227) (1,736) 160
Development costs incurred............................ 5,002 2,281 385
Accretion of discount................................. 1,537 2,711 4,870
Net change in income taxes............................ (9,776) 2,120 7,544
Purchases of reserves in place........................ 31,309 4,403 3,282
Sales of reserves in place............................ (14,456) (57) (2,480)
Net change due to revision in quantity estimates...... (7,591) (3,192) 2,289
Changes in production rates (timing) and other........ (175) (5,804) (947)
-------- ------- --------
Standardized measure, end of year..................... $ 22,843 $10,156 $ 19,760
======== ======= ========
</TABLE>
13. REVENUE ALLOWANCE ON GROSS AMOUNTS BILLED:
The following table sets forth the activity in the Company's Revenue
Allowance on Gross Amounts Billed for each of the three years in the period
ended December 31, 1999 (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Beginning balance....................................... $ 1,335 $ 1,822 $ 1,021
Additions............................................... 1,923 2,998 3,058
Deductions.............................................. (1,469) (3,485) (2,257)
------- ------- -------
Ending balance.......................................... $ 1,789 $ 1,335 $ 1,822
======= ======= =======
</TABLE>
See Note 2 for a detailed discussion regarding the Company's accounting
policy on the Revenue Allowance on Gross Amounts Billed.
44
<PAGE> 47
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED):
The offshore marine construction industry in the Gulf of Mexico is highly
seasonal as a result of weather conditions and the timing of capital
expenditures by the oil and gas companies. Historically, a substantial portion
of the Company's services has been performed during the summer and fall months.
As a result, historically a disproportionate portion of the Company's revenues
and net income is earned during such period. The following is a summary of
consolidated quarterly financial information for 1999 and 1998.
<TABLE>
<CAPTION>
QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Fiscal 1999
Revenues................................. $26,006 $34,104 $58,470 $42,374
Gross profit............................. 5,257 5,724 17,955 8,315
Net income............................... 2,087 2,641 9,017 3,154
Net income per share:
Basic.................................. .14 .18 .59 .20
Diluted................................ .14 .18 .58 .20
Fiscal 1998
Revenues................................. $33,157 $38,526 $42,913 $37,291
Gross profit............................. 10,563 12,134 15,116 11,395
Net income............................... 5,243 5,954 7,577 5,351
Net income per share:
Basic.................................. 0.36 0.41 0.52 0.37
Diluted................................ 0.35 0.40 0.51 0.36
</TABLE>
15. SUBSEQUENT EVENTS (UNAUDITED):
Acquisition of Offshore Blocks
During the first quarter of 2000 ERT acquired interests in six offshore
blocks from EEX Corporation and agreed to operate the remaining EEX properties
on the Outer Continental Shelf (OCS). The acquired offshore blocks include
working interests from 40% to 75% in five platforms, one caisson and 13 wells
currently producing 23 mmcf per day (13 mmcf net). ERT exchanged cash of $4.9
million and assumed EEX's prorated share of the abandonment obligation for the
acquired interests, and entered into a two-year contract to manage the remaining
EEX operated properties. EEX personnel who operated these properties also became
ERT employees.
45
<PAGE> 48
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 2000 Annual
Meeting of Shareholders. See also "Executive Officers of the Registrant"
appearing in Part I of this Report.
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 2000 Annual
Meeting of Shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 2000 Annual
Meeting of Shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 2000 Annual
Meeting of Shareholders.
46
<PAGE> 49
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
1. Financial Statements
The following financial statements included on pages 28 through 45 in
this Annual Report are for the fiscal year ended December 31, 1999.
Independent Auditors' Report.
Consolidated Balance Sheets as of December 31, 1999 and 1998.
Consolidated Statements of Operations for the Years Ended December 31,
1999, 1998 and 1997.
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 1999, 1998 and 1997.
Consolidated Statements of Cash Flows for the Years Ended December 31,
1999, 1998 and 1997.
Notes to Consolidated Financial Statements.
Financial Statement Schedules
All financial statement schedules are omitted because the information
is not required or because the information required is in the financial
statements or notes thereto.
(2) Report on Form 8-K.
None.
(3) Exhibits.
Pursuant to Item 601(b)(4)(iii), the Registrant agrees to forward to the
commission, upon request, a copy of any instrument with respect to long-term
debt not exceeding 10% of the total assets of the Registrant and its
consolidated subsidiaries.
The following exhibits are filed as part of this Annual Report:
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
3.1 -- Amended and Restated Articles of Incorporation of
Registrant, incorporated by reference to Exhibit 3.1 to
the Form S-1 Registration Statement filed by the Company
on May 1, 1997 (Reg. No. 333-26357).
3.2 -- Bylaws of Registrant, incorporated by reference to
Exhibit 3.2 to the Form S-1 Registration Statement filed
by the Company on May 1, 1997 (Reg. No. 333-26357).
4.1 -- Amended and Restated Loan and Security Agreement by and
among the Company, ERT and Fleet Capital Corporation
(f/n/a Shawmut Capital Corporation) dated as of May 23,
1995, incorporated by reference to Exhibit 4.1 to the
Form S-1 Registration Statement filed by the Registrant
on May 1, 1997 (Reg. No. 333-26357).
4.2 -- Amendment No. 5 to Loan, incorporated by reference to
Exhibit 4.2 to the Form S-1 Registration Statement filed
by the Company on May 1, 1997 (Reg. No. 333- 26357).
4.3 -- Form of Common Stock certificate, incorporated by
reference to Exhibit 4.1 to the Form S-1 filed by the
Company on May 1, 1997 (Reg. No. 333-26357).
</TABLE>
47
<PAGE> 50
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
4.4 -- Shareholders Agreement by and among the Company, First
Reserve Secured Energy Asset Fund, First Reserve Fund V,
First Asset Fund, First Reserve Fund V, First Reserve
Fund V-2, First Reserve Fund (collectively the "Selling
Shareholders"), Messrs. Kratz, Nelson and other
shareholders of the Company incorporated by reference to
Exhibit 4.4 to the Form S-1 Registration Statement filed
by the Company on May 1, 1997 (Reg. No. 333-26357).
4.5 -- Registration Rights Agreement by and between the Company,
the Selling Shareholders, Messrs. Kratz, Nelson and other
shareholders of the Company incorporated by reference to
Exhibit 4.5 to the Form S-1 Registration Statement filed
by the Company on May 1, 1997 (Reg. No. 333-26357).
4.6 -- Registration Rights Agreement by and between the Company
and Coflexip incorporated by reference to Exhibit 4.6 to
the Form S-1 Registration Statement filed by the Company
on May 1, 1997 (Reg. No. 333-26357).
10.1 -- Purchase Agreement dated April 11, 1997 by and between
Coflexip and the Company incorporated by reference to
Exhibit 10.1 to the Form S-1 Registration Statement filed
by Company on May 1, 1997 (Reg. No. 333-26357).
10.3 -- 1995 Long Term Incentive Plan, as amended incorporated by
reference to Exhibit 10.3 to the Form S-1 Registration
Statement filed by Company on May 1, 1997 (Reg. No.
333-26357).
*10.2 -- 1999 Annual Incentive Compensation Program.
10.5 -- Employment Agreement between Owen Kratz and the Company
dated February 28, 1999.
10.6 -- Employment Agreement between Martin R. Ferron and the
Company dated February 28, 1999.
10.7 -- Employment Agreement between S. James Nelson and the
Company dated February 28, 1999.
10.8 -- Employment Agreement between Louis L. Tapscott and the
Company dated February 28, 1999.
21.1 -- Subsidiaries of the Registrant. The Company has four
subsidiaries, Energy Resource Technologies, Inc., Cal
Dive Offshore, Ltd., Aquatica, Inc. and
*23.1 -- Consent of Arthur Andersen LLP.
*27.1 -- Financial Data Schedule.
</TABLE>
- ---------------
Management contract or compensation plan.
* Filed herewith.
48
<PAGE> 51
SIGNATURES
Pursuant to the requirements option 13 or 15 (d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned. thereunto duly authorized.
CAL DIVE INTERNATIONAL, INC.
By: /s/ S. JAMES NELSON
----------------------------------
S. James Nelson
Executive Vice President, Chief
Financial Officer
March 29, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ OWEN KRATZ Chairman, Chief Executive Officer April 7, 2000
- ----------------------------------------------------- and Director
Owen Kratz
/s/ MARTIN R. FERRON President, Chief Operating April 7, 2000
- ----------------------------------------------------- Officer and Director
Martin R. Ferron
/s/ S. JAMES NELSON Executive Vice President, Chief April 7, 2000
- ----------------------------------------------------- Financial Officer and Director
S. James Nelson
/s/ A. WADE PURSELL Vice President -- Finance, Chief April 7, 2000
- ----------------------------------------------------- Accounting Officer
A. Wade Pursell
/s/ GORDON F. AHALT Director April 7, 2000
- -----------------------------------------------------
Gordon F. Ahalt
/s/ BERNARD J. DUROC-DANNER Director April 7, 2000
- -----------------------------------------------------
Bernard J. Duroc-Danner
/s/ CLAIRE GIRAUT Director April 7, 2000
- -----------------------------------------------------
Claire Giraut
/s/ ALINE MONTEL Director April 7, 2000
- -----------------------------------------------------
Aline Montel
/s/ KEVIN WOOD Director April 7, 2000
- -----------------------------------------------------
Kevin Wood
</TABLE>
49
<PAGE> 52
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
3.1 -- Amended and Restated Articles of Incorporation of
Registrant, incorporated by reference to Exhibit 3.1 to
the Form S-1 Registration Statement filed by the Company
on May 1, 1997 (Reg. No. 333-26357).
3.2 -- Bylaws of Registrant, incorporated by reference to
Exhibit 3.2 to the Form S-1 Registration Statement filed
by the Company on May 1, 1997 (Reg. No. 333-26357).
4.1 -- Amended and Restated Loan and Security Agreement by and
among the Company, ERT and Fleet Capital Corporation
(f/n/a Shawmut Capital Corporation) dated as of May 23,
1995, incorporated by reference to Exhibit 4.1 to the
Form S-1 Registration Statement filed by the Registrant
on May 1, 1997 (Reg. No. 333-26357).
4.2 -- Amendment No. 5 to Loan, incorporated by reference to
Exhibit 4.2 to the Form S-1 Registration Statement filed
by the Company on May 1, 1997 (Reg. No. 333- 26357).
4.3 -- Form of Common Stock certificate, incorporated by
reference to Exhibit 4.1 to the Form S-1 filed by the
Company on May 1, 1997 (Reg. No. 333-26357).
4.4 -- Shareholders Agreement by and among the Company, First
Reserve Secured Energy Asset Fund, First Reserve Fund V,
First Asset Fund, First Reserve Fund V, First Reserve
Fund V-2, First Reserve Fund (collectively the "Selling
Shareholders"), Messrs. Kratz, Nelson and other
shareholders of the Company incorporated by reference to
Exhibit 4.4 to the Form S-1 Registration Statement filed
by the Company on May 1, 1997 (Reg. No. 333-26357).
4.5 -- Registration Rights Agreement by and between the Company,
the Selling Shareholders, Messrs. Kratz, Nelson and other
shareholders of the Company incorporated by reference to
Exhibit 4.5 to the Form S-1 Registration Statement filed
by the Company on May 1, 1997 (Reg. No. 333-26357).
4.6 -- Registration Rights Agreement by and between the Company
and Coflexip incorporated by reference to Exhibit 4.6 to
the Form S-1 Registration Statement filed by the Company
on May 1, 1997 (Reg. No. 333-26357).
10.1 -- Purchase Agreement dated April 11, 1997 by and between
Coflexip and the Company incorporated by reference to
Exhibit 10.1 to the Form S-1 Registration Statement filed
by Company on May 1, 1997 (Reg. No. 333-26357).
*10.2 -- 1999 Annual Incentive Compensation Program.
10.3 -- 1995 Long Term Incentive Plan, as amended incorporated by
reference to Exhibit 10.3 to the Form S-1 Registration
Statement filed by Company on May 1, 1997 (Reg. No.
333-26357).
10.5 -- Employment Agreement between Owen Kratz and the Company
dated February 28, 1999.
10.6 -- Employment Agreement between Martin R. Ferron and the
Company dated February 28, 1999.
10.7 -- Employment Agreement between S. James Nelson and the
Company dated February 28, 1999.
10.8 -- Employment Agreement between Louis L. Tapscott and the
Company dated February 28, 1999.
</TABLE>
<PAGE> 53
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
21.1 -- Subsidiaries of the Registrant. The Company has four
subsidiaries, Energy Resource Technologies, Inc., Cal
Dive Offshore, Ltd., Aquatica, Inc. and
*23.1 -- Consent of Arthur Andersen LLP.
*27.1 -- Financial Data Schedule.
</TABLE>
- ---------------
* Filed herewith.
<PAGE> 1
EXHIBIT 10.2
1999 ANNUAL INCENTIVE COMPENSATION PROGRAM
================================================================================
COMPENSATION PHILOSOPHY
CDI Incentive Compensation Plans are designed to align the interests of
employees with those of Cal Dive shareholders to the maximum extent
possible. Employees will share in the superior performance of the company
recognizing that the shareholders are entitled to a threshold level of
performance in exchange for base salaries. The threshold level is based on
the Annual Budget established by management and approved by the Board of
Directors. Incentives based upon performance above that threshold level can
result in total cash compensation to CDI employees well above competitive
levels for the industry.
The 1999 Incentive Compensation Program is a direct continuation of the program
established in 1993. It is designed to reward key team members for the
contribution made towards achieving the company's growth and profitability
targets. Potential bonuses under this program are limited only by the success
and cost effectiveness of our combined effort.
General terms of the 1999 Plan (which is based upon the 1998 Incentive
Compensation Plan which was established after review by the Human Capital
Services Division of Arthur Andersen LLP) include:
* THRESHOLD PERFORMANCE: Incentive compensation is earned when financial
performance exceeds 100% of the 1999 Business Plan (up from 80% last
year).
* PARTICIPATION: Continued expanded participation in the Operations pool
(i.e., Project Management et al) to reflect, among other things, the
significance of the Morgan City Operations Base.
* BONUS POOL: The bonus pool of the Operations Group will change to 50%
of the first $4 million over the incentive target and thereafter revert
to the 25%. The Administrative pool adds 25% of the first $2 million
over the incentive target and thereafter reverts to 6% (as last year).
* SG&A: Operations pool is increased or decreased by variances to
budgeted SG&A expenses (as defined); i.e., Sales Department and
administrative costs related to personnel in the Operations pool (same
as last year).
* DISCRETIONARY COMPONENT: 30% of the allocated incentive award is based
upon discretion of Senior management and achievement of individual
goals (same as last year).
* SUPPORT STAFF: Each Group may use a portion of their bonus pool or
incentives not awarded in the discretionary component to make bonus
payments to support staff.
Page 1
<PAGE> 2
GENERAL CONDITIONS TO ALL PLANS
================================================================================
ELIGIBILITY FOR PARTICIPATION
Participants must be on the payroll no later than June 30, 1999.
Participants who are not on the payroll as of January 1, 1999, will have
their OPPORTUNITY pro-rated by their months of service.
Incentive compensation awards will be granted to those participants who
have met the performance criteria set forth in this policy and who are on
the payroll December 31, 1999, for incentive compensation authorized under
this plan. This plan is not to be construed in any way as a guarantee of
employment or an employment contract.
METHOD OF PAYMENT
Earned incentive compensation will be paid in cash by March 15.
CLARIFICATION/INTERPRETATION/MODIFICATION OF THE PLAN
The Compensation Committee of the Cal Dive Board of Directors shall have
the right and the sole authority at any time and without restriction to
clarify, interpret and/or modify this plan.
Page 2
<PAGE> 3
PROJECT MANAGEMENT GROUP
SPECIAL PROJECTS GROUP
ACCOUNT MANAGER GROUP
MORGAN CITY OPERATIONS GROUP
================================================================================
This program is for the benefit of certain personnel in the Groups listed above,
the Vice Presidents of these Groups, and such other participants as determined
by the Group Vice Presidents and Executive Management.
Each eligible participant's incentive compensation OPPORTUNITY will be based on
the following:
1. No incentive will be paid until attaining 1999 budgeted "Subsea
Division" (exclusive of ERT) gross profit of $29,179,000.
2. Variances to budgeted Subsea SG&A (as defined) will be added to (or
deducted from) gross profit in determining 1 above.
3. A bonus pool will be established equal to (a) 50% of the first four
million dollars of gross profit (as adjusted) in excess of the goal,
plus (b) 25% of any Subsea Division gross profits in excess of
$33,179,000 subject to a cap of $3.0 million.
The bonus pool will be divided into three tiers and will be available as an
incentive compensation OPPORTUNITY for each eligible participant in direct
proportion to the ratio of the eligible participant base salaries. Each
participant's OPPORTUNITY will be awarded based as follows:
1. 70% of the total opportunity will be awarded based on achieving the
financial goals.
2. From 0 to 30% of the total opportunity will be awarded based on a
subjective evaluation by Executive Management regarding the
individual's efforts, contribution and success in achieving specific
goals established by the group Vice President and Martin Ferron. Any
portion of the opportunity that is not awarded may be reallocated to
other plan participants.
3. Discretionary bonuses may be paid to support staff from the bonus pool
or incentives not awarded in the discretionary component.
The gross profit goal reflects management's assessment of revenue producing
assets on hand or expected to be acquired at the time the Business Plan is
prepared. The goal shall NOT be adjusted should any of these assets be sold or
not acquired subsequent to the Business Plan being approved by the Board of
Directors. However, if the company subsequently purchases or otherwise acquires
new assets with the expectation of increasing the gross profit of the Subsea
division, the gross profit levels will be adjusted to allow for a reasonable
return to the company. This adjustment will be based on the economics presented
to the Board of Directors as justification for the new equipment or service (the
approved AFE) and will be prorated for months in service. In addition, gross
profit is NOT to be adjusted for changes in accounting policy made during a
fiscal year.
Page 3
<PAGE> 4
EXECUTIVE MANAGEMENT
ACCOUNTING & ADMINISTRATIVE PERSONNEL
================================================================================
This program is for the benefit of certain members of executive management and
corporate accounting and administrative personnel.
Each eligible participant's incentive compensation opportunity will be based
upon the following:
1. Attaining the consolidated net income of $19,500,000 as budgeted in
the 1999 Business Plan.
2. Upon attaining the net income goal, a bonus pool equal to 75% of all
eligible persons assigned bonus percentages will be created
3. In addition, a bonus pool will be established based upon (a) 25% of the
first $2 million of net income in excess of targeted net income, plus
(b) 6% of any consolidated net income in excess of targeted net income
plus $2 million.
The bonus pool will be available for each eligible participant in direct
proportion to the ratio of eligible participant base salaries. Each participants
opportunity will be awarded based as follows:
1. 70% of the total opportunity will be awarded based upon achieving
financial goals.
2. From 0 to 30% of the total opportunity will be awarded based upon a
subjective evaluation by the Compensation Committee and Executive
Management regarding the individual's efforts, contribution and success
in achieving specific goals established by the Group Vice President and
Board of Directors. Any portion of the opportunity that is not awarded
may not be reallocated to other participants.
3. Discretionary bonuses may be paid to support staff from the bonus pool
or incentives not awarded in the discretionary component.
If the company purchases or otherwise acquires new assets with the expectation
of increasing the net income of Subsea Division, consolidated net income will be
adjusted to allow for a reasonable return to the company. This adjustment will
be based on the economics presented to the Board of Directors for justification
for the new equipment or service (the approved AFE) and will be prorated for
months in service.
Page 4
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our report dated February 17, 2000, included in this Form 10-K into the
Company's previously filed Registration Statements File No. 333-50289 and No.
333-58817.
/s/ ARTHUR ANDERSEN LLP
Houston, Texas
March 30, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 19,996
<SECURITIES> 0
<RECEIVABLES> 53,410
<ALLOWANCES> 1,789
<INVENTORY> 0
<CURRENT-ASSETS> 87,944
<PP&E> 180,519
<DEPRECIATION> 45,862
<TOTAL-ASSETS> 243,722
<CURRENT-LIABILITIES> 49,057
<BONDS> 0
0
0
<COMMON> 73,311
<OTHER-SE> 77,561
<TOTAL-LIABILITY-AND-EQUITY> 243,722
<SALES> 160,954
<TOTAL-REVENUES> 160,954
<CGS> 123,703
<TOTAL-COSTS> 136,930
<OTHER-EXPENSES> (491)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> (849)
<INCOME-PRETAX> 25,473
<INCOME-TAX> 8,465
<INCOME-CONTINUING> 16,899
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 16,899
<EPS-BASIC> 1.13
<EPS-DILUTED> 1.10
</TABLE>
