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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
AMENDMENT NO. 1
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NO. 0-22739
CAL DIVE INTERNATIONAL, INC.
(Exact name of registrant as specified in its charter)
MINNESOTA 95-3409686
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 N. SAM HOUSTON PARKWAY E.,
SUITE 400
HOUSTON, TEXAS 77060
(Address of Principal Executive Offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(281) 618-0400
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
None None
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. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [ ]
The aggregate market value of the voting stock held by non-affiliates of
the registrant as of June 28, 2002 was $759,567,754 based on the last reported
sales price of the Common Stock on June 28, 2002, as reported on the
NASDAQ/National Market System.
The number of shares of the registrant's Common Stock outstanding as of
March 17, 2003 was 37,632,058.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement for the Annual Meeting of
Shareholders to be held on May 14, 2003, are incorporated by reference into Part
III hereof.
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CAL DIVE INTERNATIONAL, INC. ("CDI") INDEX -- FORM 10-K
PAGE
----
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 17
Item 3. Legal Proceedings........................................... 21
Item 4. Submission of Matters to a Vote of Security Holders......... 22
Unnumbered Executive Officers of the Company........................... 22
Item
PART II
Item 5. Market for the Registrant's Common Equity and Related
Shareholder Matters....................................... 24
Item 6. Selected Financial Data..................................... 24
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 26
Item 7A Quantitative and Qualitative Disclosure About Market Risk... 36
Item 8. Financial Statements and Supplementary Data................. 38
Independent Auditors' Report................................ 39
Consolidated Balance Sheets -- December 31, 2002 and 2001... 41
Consolidated Statements of Operations -- Three Years Ended
December 31, 2002, 2001 and 2000.......................... 42
Consolidated Statements of Shareholders' Equity -- Three
Years Ended December 31, 2002, 2001 and 2000.............. 43
Consolidated Statements of Cash Flows -- Three Years Ended
December 31, 2002, 2001 and 2000.......................... 44
Notes to Consolidated Financial Statements.................. 45
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure.................................. 67
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 67
Item 11. Executive Compensation...................................... 67
Item 12. Security Ownership of Certain Beneficial Owners and
Managers.................................................. 67
Item 13. Certain Relationships and Related Transactions.............. 67
Item 14. Controls and Procedures..................................... 67
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 68
Signatures.................................................. 71
Certifications.............................................. 72
i
This Amendment No. 1 on Form 10-K/A to Cal Dive International, Inc.'s
Annual Report on Form 10-K for the year ended December 31, 2002, filed with the
Securities and Exchange Commission on March 28, 2003, is being filed to reflect
conforming reclassifications to Subsea and Salvage Identifiable Assets within
"Notes to Consolidated Financial Statements -- Business Segment Information"
included in Part III, Note 14.
PART I
ITEM 1. BUSINESS.
OVERVIEW
We are an energy services company specializing in subsea construction and
well operations as well as providing oil and gas companies with alternatives to
traditional approaches of equity sharing in offshore properties. We operate
primarily in the Gulf of Mexico, or Gulf, and recently in the North Sea with
services that cover the lifecycle of an offshore oil and gas field. We believe
we have a longstanding reputation for innovation in our subsea construction
techniques, equipment design and methods of partnering with customers. Our
diversified fleet of 23 vessels and 21 remotely operated vehicles (or ROVs) and
trencher systems perform services that support drilling, well completion,
intervention, construction and decommissioning projects involving pipelines,
production platforms, risers and subsea production systems. We also have
acquired significant interests in oil and gas properties and related production
facilities as part of our Production Partnering business. Our customers include
major and independent oil and gas producers, pipeline transmission companies and
offshore engineering and construction firms.
We have positioned ourselves for work in water depths greater than 1,000
feet, referred to as the Deepwater, by continuing to grow our technically
advanced fleet of dynamically positioned, or DP, vessels, ROVs and the number of
highly experienced support professionals we employ. In early 2002, we purchased
our new ROV subsidiary, Canyon Offshore, Inc., that offers survey, engineering,
repair, maintenance and international cable burial services in the Gulf, North
Sea and Southeast Asia. Later in mid-2002, our Well Ops (U.K.) Limited
subsidiary purchased the North Sea well operations business unit of
Technip-Coflexip ("Technip") including one large DP vessel, work contracts and
personnel. This fleet of DP vessels serves as advanced work platforms for the
subsea solutions that we provide with our alliance partners, a group of
internationally recognized contractors and manufacturers. Most notably, the
Q4000, our Deepwater semi-submersible multi-service vessel, or MSV, incorporates
patented technologies that can improve Deepwater well completion, intervention
and construction economics for our customers. Availability of the Q4000, and
four other large vessels that we recently purchased or upgraded, the Eclipse,
Mystic Viking, Intrepid and Seawell, enables us to offer a diverse fleet of DP
subsea construction and intervention vessels (four of which are based in the
Gulf).
On the Outer Continental Shelf, or OCS, in water depths up to 1,000 feet,
we perform traditional subsea services, including air and saturation diving and
salvage work. Our shallow operations division, Aquatica, provides a full
complement of services in the shallow water market from the shore to a depth of
300 feet. Aquatica's eight vessels are permanently dedicated to performing
traditional diving services. In depths from 300 feet to 1,000 feet, these
services are provided by our two four-point saturation diving vessels, with
another five DP vessels capable of providing such services, on the OCS. We
provide marine construction services in the OCS "spot market" where projects are
generally turnkey in nature, short in duration (two to thirty days), and require
the availability of multiple vessels due to frequent rescheduling. The technical
and operational experience of our personnel and the scheduling flexibility
offered by our large fleet enable us to manage turnkey projects and to meet our
customers' requirements. We have also established a presence in the salvage
market by offering customers a number of options to address their
decommissioning obligations in a cost-efficient manner, particularly the removal
of smaller structures. Our alliance with Horizon Offshore, Inc. provides derrick
barge and heavy lift capacity for the removal of larger structures.
In our Production Partnering business, our subsidiary Energy Resource
Technology, Inc., or ERT, acquires and produces mature, non-core offshore
property interests, offering customers a cost-effective
1
alternative to the decommissioning process required by law. Market conditions in
2002 allowed ERT to add significantly to its property base through large
property acquisitions from Williams Production RMT Company (a subsidiary of the
Williams Companies), Amerada Hess Corporation, subsidiaries of Shell Exploration
and Production Company, and a venture consisting of Murphy Exploration &
Production Company ("Murphy") and Callon Petroleum Operating Company ("Callon"),
adding over 70 BCFe to ERT's reserves. In the acquisition from the Murphy/Callon
joint venture, ERT acquired and successfully developed a "Stranded Field"
property, i.e., one where the exploratory well had encountered proven reserves
yet the reserves were of a marginal size to Murphy while Callon was constrained
by capital expenditure requirements. We also expanded our Production Partnering
strategy through participation in the ownership of the TLP production facility
for the Marco Polo field, a Deepwater Gulf oil and gas exploration project
operated by Anadarko Petroleum Corporation. We expect that owning this
tension-leg platform, or TLP, in a 50/50 joint venture with El Paso Energy
Partners, L.P. will generate income for us in the future and also provide us
with additional construction work for Cal Dive and farm-in opportunities for
ERT. ERT's reservoir engineering and geophysical expertise enabled us in 2000 to
acquire a working interest in Gunnison, a Deepwater Gulf oil and natural gas
exploration project, in partnership with the operator, Kerr-McGee Corporation.
We anticipate that these investments will generate income for us in the future
and will also help secure utilization for our subsea assets. At both Gunnison
and Marco Polo, we participate in field development planning and have been
contracted to perform subsea construction work.
Cal Dive was incorporated in Minnesota in 1983 as a successor to California
Divers, Inc. a company originally incorporated in 1964. We make available
through our website, www.caldive.com, our Annual Report on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K, and amendments to those
reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange
Act as soon as reasonably practicable after we electronically file such material
with, or furnish it to, the SEC.
Our overall corporate goal is to increase shareholder value by
strengthening our market position to provide a return that leads our Peer Group.
We have been able to achieve our return on capital objective by focusing on the
following business strengths and strategies.
OUR STRENGTHS
Fleet of DP Vessels. Our fleet of DP vessels and ROVs is one of the
largest permanently deployed in the Gulf, with one of the most diverse and
technically advanced collections of subsea intervention and construction
capabilities. The comprehensive services provided by our DP vessels are both
complementary and overlapping, enabling us to provide customers the redundancy
essential for most projects, especially in the Deepwater.
Formation of New Well Operations Subsidiary as a "First In" Advantage. In
2002 we formed a new wholly owned subsidiary, Well Ops Inc., to provide offshore
oil and gas operators with the experience, expertise and technology for
cost-effective subsea well operations. Establishment of the Well Ops group
followed the construction of the purpose-built Q4000 and the acquisition of the
Subsea Well Operations Business Unit of Technip in Aberdeen, Scotland. The
mission of the new companies is to provide the industry with a single,
comprehensive source for addressing current well operations needs and to
engineer for future needs.
Experienced Personnel and Turnkey Contracting. A key element of our
successful growth has been our ability to attract and retain experienced
personnel who are among the best in the industry at providing turnkey
contracting. We believe the recognized skill of our personnel and our successful
operating history uniquely position us to capitalize on the trend in the oil and
gas industry of increased outsourcing to contractors and suppliers.
Major Provider of Marine Construction Services on the OCS. We believe that
our expansion of Aquatica, our alliance with Horizon, and our position in the
Gulf for saturation diving services make us the largest supplier of marine
construction services on the OCS. We expect the ongoing depletion of existing
reserves, coupled with growing demand for natural gas, to require increased
exploitation and development of OCS reservoirs.
2
Production Partnering. The strategy of ERT's oil and gas production
business differentiates us from our competitors and helps to offset the cyclical
nature of our marine construction operations. Each of ERT's oil and gas
investments is designed to secure utilization of CDI construction vessels. Our
long-term goal is that 40% of all of our construction utilization is provided by
ERT's ownership of offshore fields and production facilities.
Decommissioning Operations. Over the last decade, we have established a
presence in decommissioning offshore facilities, particularly in the removal of
the smaller structures and caissons that make up approximately half of the
structures in the Gulf. We expect demand for decommissioning services to
increase due to the significant backlog of platforms and caissons that must be
removed in accordance with government regulations.
OUR STRATEGIES
Focusing on the Gulf. We will continue to focus on the Gulf of Mexico,
where we have provided marine construction services since 1975. We expect oil
and gas exploration and development activity in the Gulf, particularly in the
Deepwater, to increase over the next several years.
Capturing a Leading Presence in the Deepwater Market. We have recently
expanded our fleet to service Deepwater projects by purchasing the Mystic
Viking, a 242 foot DP vessel; the Eclipse, a large mono-hull vessel with
significant deck load capacity; and the Seawell, a purpose built DP well
operations vessel. In addition, in 2002 we took delivery of the Q4000 and the
Intrepid. Our fleet now includes nine world-class DP vessels, seven of which are
based in the Gulf of Mexico. In addition, through Canyon we now own and operate
21 ROV and trencher systems. Canyon represents an integration that is consistent
with our strategy of controlling all aspects along the critical path of
significant projects. In addition, we are presently building a "T750" Super
Trencher as well as 3 Triton XLS ROV systems to fulfill requirements under a
Master Service Agreement entered into with Technip.
Developing Well Operations Niche. It is estimated that over 2,000 subsea
trees will be installed in the years 2002 through 2006. Currently there are few
cost-effective solutions for subsea well operations to troubleshoot or enhance
production, shift zones or perform recompletions, as all such work today must
generally be done from drilling rigs. Our three purpose-built vessels serve as
work platforms for well operations services at costs significantly less than
drilling rigs. In the Gulf of Mexico, the new, multi-service semi-submersible
Q4000 and the Uncle John have set a series of "firsts" in increasingly deep
water without the use of a rig. In the North Sea, the Seawell has provided
intervention and abandonment services for more than 400 North Sea wells since
her commissioning in 1987. Competitive advantages of the CDI vessels stem from
their lower operating costs, ability to mobilize quickly and to maximize
productive time by performing a broad range of tasks for intervention,
construction, inspection, repair and maintenance.
Acquiring Mature Oil and Gas Properties. Through ERT we have been
acquiring mature or sunset properties since 1992, thereby providing customers a
cost effective alternative to the decommissioning process. In the last ten years
we have acquired interests in 89 leases and currently are the operator of 42 of
63 active offshore leases. ERT has been able to achieve a significant return on
capital by efficiently developing acquired reserves, lowering lease operating
expenses and adding new reserves through well work. Our customers consider ERT a
preferred buyer as ERT is a bonded offshore operator and has access to Cal
Dive's decommissioning assets. As the industry wide leader of acquiring mature
properties, ERT has a significant flow of potential acquisitions. At December
31, 2002, ERT's total proven reserves were 157.5 BCFe, including 73.8 BCFe of
initial proved reserves assigned to our ownership position in Gunnison.
Expanding Ownership in Deepwater Developments. Cal Dive has a 20% working
interest position in the Deepwater Gunnison field and owns 50% of the tension
leg production platform being constructed with El Paso Energy Partners for the
Marco Polo field. Ownership of the TLP provides a transmission type return which
does not entail any reservoir or commodity price risk. The Company plans to seek
additional opportunities to invest in such production facilities.
3
Expanding the Stranded Field Model. Drilling activity in the Gulf since
1998 has consistently exceeded 70 exploratory wells per year with approximately
30% resulting in new discoveries. Because of the smaller size of the reservoirs
today, there are many commercial discoveries in the Deepwater Gulf of Mexico
that have yet to be brought into production. In addition, many of the wells
deemed non-commercial or those in non-core areas are attractive to the Company.
During 2002, the Company acquired and successfully developed its first proved
undeveloped reserve ("PUD") prospect, East Cameron 374, a field acquired from
Murphy Exploration and Callon. The Eclipse and Cal Diver I assisted in the
successful development of this field. Depending upon the water depth,
development of these fields may require state of the art equipment such as the
Q4000, a more specialized asset such as the Intrepid, for pipelay or a
combination of Cal Dive contracting assets. The Company is considering a number
of alternatives that would provide outside investor funding to expand this
market niche.
THE INDUSTRY
The offshore oilfield services industry in the Gulf originated in the early
1950s to assist companies as they began to explore and develop offshore fields.
The industry has grown significantly since the early 1970s as the domestic oil
and gas industry has increasingly relied upon these fields for new production.
The oilfield services industry benefits from a number of trends including the
following:
- lack of growth in natural gas production and failure to construct new
subsea construction assets in the face of foreign dependency and
increasing U.S. and world demand;
- advances in exploration, extraction and production technology that have
enabled industry participants to more cost-effectively enter the
Deepwater Gulf; and
- increased demand for decommissioning services as the offshore oil and gas
industry continues to mature.
In response to the oil and gas industry's ongoing migration to the
Deepwater, equipment and vessel requirements have changed. Most vessels
currently operating in the Deepwater Gulf were designed in the 1970s and 1980s
for work in a maximum depth of approximately 1,000 feet. These vessels have been
modified to take advantage of new technologies and now operate in depths up to
4,000 feet. We believe there is demand in the Gulf for new generation vessels,
such as the Q4000 and Intrepid, that are specifically designed to work in water
depths up to 10,000 feet.
Defined below are certain terms and ideas helpful to understanding the
services we perform in support of offshore development:
BCFe: When describing oil and gas, the term converts oil volumes to
their energy equivalent in natural gas and combines them in billions of
cubic feet equivalent.
Deepwater: Water depths beyond 1,000 feet.
Dive Support Vessel (DSV): Specially equipped vessel which performs
services and acts as an operational base for divers, ROVs and specialized
equipment.
Dynamic Positioning (DP): Computer-directed thruster systems that use
satellite-based positioning and other positioning technologies to ensure
the proper counteraction to wind, current and wave forces enable the vessel
to maintain its position without the use of anchors. Two DP systems (DP-2)
are necessary to provide the redundancy required to support safe deployment
of divers, while only a single DP system is necessary to support ROV
operations.
DP-2: Redundancy allows the vessel to maintain position even with
failure of one DP system. Required for vessels which support both manned
diving and robotics and for those working in close proximity to platforms.
EHS: Environment, Health and Safety programs to protect the
environment, safeguard employee health and eliminate injuries.
4
E&P: Companies involved in oil and gas exploration and production
activities.
Life of Field Services: Includes services performed on facilities,
trees and pipelines from the beginning to the economic end of the life of
an oil field, including installation, inspection, maintenance, repair,
contract operations, well intervention, recompletion and abandonment.
MBbl: When describing oil, refers to 1,000 barrels containing 42
gallons each.
Minerals Management Service (MMS): The federal regulatory body having
responsibility for United States waters in the Gulf.
MMcf: When describing natural gas, refers to 1 million cubic feet.
Moonpool: An opening in the center of a vessel through which a
saturation diving system or ROV may be deployed, allowing safe deployment
in adverse weather conditions.
Outer Continental Shelf (OCS): For purposes of our industry, areas in
the Gulf from the shore to 1,000 feet of water depth.
Peer Group: Defined in this Annual Report as comprising Global
Industries, Ltd. (Nasdaq: GLBL), Horizon Offshore, Inc. (Nasdaq: HOFF),
McDermott International, Inc. (NYSE: MDR), Oceaneering International, Inc.
(NYSE: OII), Stolt Offshore SA (Nasdaq: SOSA), Technip-Coflexip (NYSE:
TKP), and Torch Offshore, Inc. (Nasdaq: TORC).
Production Partnering: Alternative approach (i) to equity sharing in
offshore properties through the purchase of mature fields and those fields
where exploratory drilling encountered less than expected reserves and (ii)
to ownership of production facilities.
Proved Undeveloped Reserve (PUD): Proved undeveloped oil and gas
reserves that are expected to be recovered from a new well on undrilled
acreage, or from existing wells where a relatively major expenditure is
required for recompletion.
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 Diving: Saturation diving, required for work in water
depths between 300 and 1,000 feet, involves divers working from special
chambers for extended periods at a pressure equivalent to the pressure at
the work site.
Spar: Floating production facility anchored to the sea bed with
catenary mooring lines.
Spot Market: Prevalent market for subsea contracting in the Gulf,
characterized by projects generally short in duration and often of a
turnkey nature. These projects often require constant rescheduling and the
availability or interchangeability of multiple vessels.
Stranded Field: Smaller reservoir that standing alone may not justify
the economics of a host production facility and/or infrastructure
connections.
Subsea Construction Vessels: Subsea services are typically performed
with the use of specialized construction vessels which provide an
above-water platform that functions as an operational base for divers and
ROVs. Distinguishing characteristics of subsea construction vessels include
DP systems, saturation diving capabilities, deck space, deck load, craneage
and moonpool launching. Deck space, deck load and craneage are important
features of the vessel's ability to transport and fabricate hardware,
supplies and equipment necessary to complete subsea projects.
Tension Leg Platform (TLP): A floating Deepwater compliant structure
designed for offshore hydrocarbon production.
Trencher or Trencher System: A subsea robotics system capable of
providing post lay trenching, inspection and burial (PLIB) and maintenance
of submarine cables and flowlines in water depths of 30 to 7,200 feet
across a range of seabed and environmental conditions.
Ultra-Deepwater: Water depths beyond 4,000 feet.
5
SUBSEA CONTRACTING
We and our alliance partners provide a full range of subsea construction
services in both the shallow water and Deepwater Gulf including:
- Exploration. Pre-installation surveys; rig positioning and installation
assistance; drilling inspection; subsea equipment maintenance; well
completion; search and recovery operations.
- Development. Installation of production platforms; installation of
subsea production systems; pipelay support including connecting pipelines
to risers and subsea assemblies; pipeline stabilization, testing and
inspection; cable and umbilical lay and connection.
- Production. Inspection, maintenance and repair of production structures,
risers and pipelines and subsea equipment; well intervention; life of
field support.
- Decommissioning. Decommissioning and remediation services; plugging and
abandonment services; platform salvage and removal; pipeline abandonment;
site inspections.
Deepwater Contracting and Well Operations
In 1994, we began to assemble a fleet of DP vessels in order to deliver
subsea services in the Deepwater and Ultra-Deepwater. Today, our fleet consists
of two semi-submersible DP MSVs, the Q4000 and the Uncle John; a dedicated well
operations vessel, the Seawell; an umbilical and rigid pipelay vessel, the
Intrepid; three construction DP DSVs, the Witch Queen, the Mystic Viking, and
the Eclipse; and two ROV support vessels, the Merlin and the Northern Canyon. In
2001, we began vessel enhancements to the Q4000 (well completion) and the
Intrepid (DP-2 capability and a 400-ton crane). The Q4000 and Intrepid were
placed into service, respectively, in April and May 2002. We purchased the
Eclipse in October of 2001 and the Seawell in July of 2002.
In 2002, we increased our ROV and trenching fleet to 21 by acquiring Canyon
Offshore, Inc. Canyon's ROVs and trenchers are designed for offshore
construction, rather than drilling rig support, and its management team added
industry experience in a setting where our vessels can add value in support of
its ROVs. As marine construction support in the Gulf of Mexico moves to deeper
waters, ROV systems will play an increasingly important role and will help to
provide our customers with vessel availability and schedule flexibility to meet
the technological challenges of Deepwater construction developments in the Gulf
and internationally. Our ROVs operate in three regions: the Americas (8),
Southeast Asia (5), and the North Sea (4). In addition to the ROVs, Canyon also
has four trenchers that operate in Southeast Asia (2) and the North Sea (2).
Furthermore, Canyon has ordered 3 new Triton XLS ROV systems and a state of the
art 750 horsepower trenching unit to fulfill its future contract obligations
under its agreement with Technip.
We assist customers in solving the operational challenges encountered in
Deepwater projects by using methods or technologies we have developed. To
enhance our ability to provide both full field development and life of field
services, we have alliances with other offshore service and equipment providers.
These alliances enable us to offer state-of-the-art products and service while
maintaining our low overhead base. These alliances are:
- Fugro-McClelland Marine Geoscience, Inc. -- Geotechnical coring and
survey
- Horizon Offshore, Inc. -- Small diameter reeled pipelay equipment
- Schlumberger Limited -- Deepwater downhole services
6
Utilization of 82% was very close to last year's record of 87% even though
we added three new vessels and elected to take several vessels out of service in
the third quarter for accelerated regulatory inspections. Major projects in 2001
and 2002 were:
DEPTH
FIELD CUSTOMER DESCRIPTION (FEET)
----- -------- ----------- ------
Diana Exxon Riser tie-in, spool and strake 4,600
installations.......................
Diana D-3 Exxon Jumper and flying lead 4,600
installations.......................
Marshall/Madison Exxon Jumper and flying lead 4,960
installations.......................
Mica Exxon Manifold, suction pile and tree 4,500
installations.......................
Nansen/Boomvang Kerr-McGee Plet, flexible riser, umbilicals 3,700
flying lead and jumper
installations.......................
King Kong Mariner Jumper and flying lead 3,400
installations.......................
Navajo Kerr-McGee Installed flex riser, 6-inch 3,700
pipeline and umbilicals.............
Falcon El Paso Energy Partners Manifold installation and jumper 3,450
metrology...........................
In late 2002, we formed a new wholly owned subsidiary, Well Ops Inc., to
provide offshore oil and gas operators with the industry's largest collection of
experience, expertise and technology for cost-effective subsea well operations.
Establishment of the Well Ops Group (Well Ops Inc. and Well Ops (U.K.) Limited)
follows the construction of the purpose-built Q4000 and the acquisition of the
subsea well operations business unit of CSO Ltd., a subsidiary of Technip. The
mission of these new companies is to provide the industry with a single,
comprehensive source for addressing current well operations needs and to
engineer for future needs. Our purpose-built vessels serve as work platforms for
well operations services at costs significantly less than drilling rigs. In the
Gulf of Mexico, the Q4000 and the Uncle John have set a series of "firsts" in
increasingly deep water without the use of a rig including: first "live subsea
well" intervention; first through tubing subsea well decommission; first "live
subsea well" intervention using wireline lubricator; first Deepwater full field
decommission; first re-entry and decommission through horizontal tree; first
removal and recovery of subsea well templates and horizontal trees; first use of
test tree in open water as a lower riser package (LRP); first subsea transfer of
tree from one well to another during decommissioning operations; first use of
coil tubing drilling in subsea decommissioning; and first installation of a
"storm choke" as replacement for subsurface safety control valve; all of which
utilized a semi-submersible DP MSV instead of a drilling rig. The Seawell has
provided intervention and abandonment services for more than 400 North Sea wells
since her commissioning in 1987. Competitive advantages of our vessels stem from
their lower operating costs and the ability to mobilize quickly and maximize
productive time by performing a broad range of tasks for intervention,
construction, inspection, repair and maintenance. Well Ops Inc. also
collaborates with the leading downhole service providers to provide a superior,
comprehensive solution. An alliance is currently in place with Schlumberger to
provide these services.
Shelf Contracting
On the OCS in water depths up to 1,000 feet, we perform traditional subsea
services including air and saturation diving in support of marine construction
activities. Eleven of our vessels are permanently dedicated to performing
traditional diving services, with another five DP vessels capable of providing
such services, on the OCS. Seven of these vessels support saturation diving. In
addition, our highly qualified personnel have the technical and operational
experience to manage turnkey projects to satisfy customers' requirements and
achieve our targeted profitability.
We deliver our services in the shallow water market, from the beach to a
depth of 300 feet, through our shallow operations division, Aquatica. In
addition, our saturation diving vessels can deliver services in depths up to
1,000 feet. We also perform numerous projects on the OCS in an alliance with
Horizon. In the late 1980s, we demonstrated that pipelay operations would be
much more effective if the expensive barge spreads
7
simply laid the pipe, allowing our DSVs to follow along and perform the more
time-consuming task of commissioning the line. Under the alliance, we have the
exclusive right to provide DSV and diving services for Horizon pipelay barges,
while Horizon supplies pipelay, derrick barge and heavy lift capacity to us. Our
interaction with Horizon is multi-faceted, including operations in addition to
those that flow from the formal alliance to provide services on the OCS. For
example, much of our work in Mexican waters has been subcontracted from Horizon.
Since 1989, we have undertaken a wide variety of decommissioning
assignments, mostly on a turnkey basis. We have established a leading position
in the removal of smaller structures, such as caissons and well protectors,
which represent approximately half of the structures in the Gulf.
PRODUCTION PARTNERING
We formed ERT in 1992 to exploit a market opportunity to provide a more
efficient solution to offshore abandonment, to expand our off-season salvage and
decommissioning activity, and to support full field production development
projects. Through Production Partnering, we offer customers the option of
selling mature offshore fields as an alternative to contracting and managing the
many phases of the decommissioning process. The benefits of our Production
Partnering strategy are fourfold. First, oil and gas revenues counteract the
volatility in revenues we experience in offshore construction. Second, in
periods of excess capacity, such as in 2002, we have the flexibility to stay out
of the competitive bid market and instead focus on negotiated contracts. Third,
our oil and gas operations generate significant cash flow that has partially
funded construction and/or modification of assets such as the Q4000, Intrepid
and Eclipse, enabling us to add technical talent to support our expansion into
the new Deepwater frontier. Finally, a major objective of our investments in oil
and gas properties is to secure the associated marine construction work.
There are over 100 discoveries in the Deepwater Gulf that have yet to be
brought into production. Many of these are smaller reservoirs that standing
alone cannot justify the economics of a host production facility. As a result,
we expect that the Deepwater Gulf will be developed in a hub and satellite field
concept that resembles the approach the airline industry has used with regional
hub locations. We expect significant opportunities as this occurs. For example,
Gunnison, our first Deepwater field development project, is a hub location where
we will provide infrastructure and tie-back marine construction services. At the
Marco Polo field, our 50% ownership in the production facility will allow us to
realize a return on investment consisting of both a fixed monthly demand charge
and a volumetric tariff charge. In addition, we will assist with the
installation of the TLP and work to develop the surrounding acreage that can be
tied back to the platform by our construction vessels.
Within ERT we have assembled a team of personnel with experience in
geology, geophysics, reservoir engineering, drilling, production engineering,
facilities management, lease operations and land. ERT generates income in three
ways: lowering salvage costs by using our assets, operating the field more cost
effectively, and extending reservoir life through well exploitation operations.
When a company sells an OCS property, they retain the financial responsibility
for plugging and decommissioning if their purchaser becomes financially unable
to do so. Thus, it becomes important that a property be sold to a purchaser who
has the financial wherewithal to perform their contractual obligations. Although
there is significant competition in this mature field market, ERT's reputation,
supported by Cal Dive's financial strength, have made it the purchaser of choice
of many major independent oil and gas companies. Despite this competition we
significantly expanded our property base in 2002 with four large acquisitions,
including one successful completion of a "stranded" field.
In June, ERT acquired a package of offshore properties from Williams
Production RMT Company (a subsidiary of the Williams Companies). The blocks
purchased represent an average 30% net working interest in 23 federal leases and
three Texas leases with 23 wells that produce the equivalent of 7.5 MMcf per
day. In August, ERT acquired the 74.8% working interest of subsidiaries of Shell
Exploration & Production Company in the South Marsh Island 130 (SMI 130) field
and completed the purchase of seven Gulf of Mexico fields from Amerada Hess
Corporation, including Hess's 25% interest in SMI 130. Currently the SMI 130
Field, with approximately 155 wells on five 8-pile platforms, produces
approximately 4,000 barrels of oil per day from
8
50 active wells. In August 2002, ERT completed the #1 well at East Cameron 374
in three zones using Cal Dive vessels. With production commingled from the lower
two zones the well is currently producing at 15.5 MMCFD and 75 BOPD. The
completion marked the first Gulf of Mexico application of Baker Oil Tools
"Intelligent Well System". The "InForce(TM) Intelligent Well System" allows ERT
to change zones via hydraulic controls on the production platform without
requiring a rig re-enter the well. This type of completion also minimizes future
well maintenance requirements.
The table below sets forth information, as of December 31, 2002, with
respect to estimates of net proved reserves and the present value of estimated
future net cash flows at such date, prepared in accordance with guidelines
established by the Securities and Exchange Commission. The Company's estimates
of reserves at December 31, 2002, excluding Gunnison, have been reviewed by
Miller and Lents, Ltd., independent petroleum engineers. These non-Gunnison
reserves totaled (as of December 31, 2002) 43,323 MMcf of natural gas and 6,727
MBbls of oil with a standardized measure of discounted future net cash flows
(pre-tax) of $161,565,600 (see note (2) in table below). Since the Company does
not own a license to the geophysical data, reserves attributable to Gunnison
(which total 47% of our proved reserves as of December 31, 2002) have been
determined based on information provided by the operator. These reserve
estimates were reviewed by our engineers, including an assessment of the
operator's assumptions and their engineering, geologic and evaluation principles
and techniques. All of the Company's reserves are located in the United States.
Proved reserves cannot 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.
TOTAL PROVED
------------
Estimated Proved Reserves(1):
Natural gas (MMcf).......................................... 85,224
Oil and condensate (MBbls).................................. 12,037
Standardized measure of discounted future net cash flows
(pre-tax)(2).............................................. $291,705,010
---------------
(1) Includes both Company's reserves reviewed by Miller & Lents (as noted above)
and Gunnison reserves reviewed by Company's engineers.
(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 December 31, 2002, we owned an interest
in 157 gross (105 net) natural gas wells and 302 gross (265 net) oil wells
located in federal and state offshore waters in the Gulf of Mexico.
CUSTOMERS
Our customers include major and independent oil and gas producers, pipeline
transmission companies and offshore engineering and construction firms. The
level of construction services required by any particular customer depends on
the size of that customer's capital expenditure budget devoted to construction
plans in a particular year. Consequently, customers that account for a
significant portion of contract revenues in one fiscal year may represent an
immaterial portion of contract revenues in subsequent fiscal years. The percent
of consolidated revenue of major customers was as follows: 2002 -- Horizon
Offshore, Inc. (10%) and BP Trinidad & Tobago LLC (11%); 2001 -- Horizon
Offshore, Inc. (18%) and Enron Corp. (10%) and 2000 -- Enron Corp. (13%). We
estimate that in 2002 we provided subsea services to over 200 customers. Our
projects are typically of short duration and are generally awarded shortly
before mobilization. Accordingly, we believe backlog is not a meaningful
indicator of future business results.
COMPETITION
The subsea services industry is highly competitive. While price is a
factor, the ability to acquire specialized vessels, to attract and retain
skilled personnel, and to demonstrate a good safety record are also
9
important. Our competitors on the OCS include Global Industries Ltd.,
Oceaneering International, Inc., Stolt Offshore S.A., Torch Offshore, Inc., and
a number of smaller companies, some of which only operate a single vessel and
often compete solely on price. For Deepwater projects, our principal competitors
include Stolt Offshore S.A., Subsea 7, Technip-Coflexip and Torch.
ERT encounters significant competition for the acquisition of mature oil
and gas properties. Our ability to acquire additional properties depends upon
our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Many potential purchasers of
oil and gas properties are well-established companies with substantially larger
operating staffs and greater capital resources.
TRAINING, SAFETY AND QUALITY ASSURANCE
We have established a corporate culture in which safety is expected to be
among the highest priorities. Our corporate goal, based on the belief that all
accidents are preventable, is to provide an injury-free workplace by focusing on
correct safety behavior. Our safety procedures and training programs were
developed by management personnel who came into the industry as divers and who
know first hand the physical challenges of the ocean work site. As a result,
management believes that our safety programs are among the best in the industry.
We have introduced a company-wide effort to enhance a behavioral safety process
and training program that makes safety a constant focus of awareness through
open communication with all offshore and yard employees. The process includes
the documentation of all daily observations and the collection of this data. In
addition, we initiated regular monthly visits by project managers to conduct
"Hazard Hunts" on each vessel, providing a "safety audit" with a fresh
perspective. Results from this program were evident as our safety performance
improved significantly in 2001 and 2002.
GOVERNMENT REGULATION
Many aspects of the offshore marine construction industry are subject to
extensive governmental regulations. We are subject to the jurisdiction of the
Coast Guard, the Environmental Protection Agency, the MMS and the U.S. Customs
Service, as well as private industry organizations such as the American Bureau
of Shipping. In the North Sea, regulations govern working hours and a specified
working environment, as well as standards for diving procedures, equipment and
diver health. These North Sea standards are some of the most stringent
worldwide. In the absence of any specific regulation, our North Sea branch
adheres to standards set by the International Marine Contractors Association and
the International Maritime Organisation.
We support and voluntarily comply with standards of the Association of
Diving Contractors International. The Coast Guard sets safety standards and is
authorized to investigate vessel and diving accidents, and to recommend improved
safety standards. The Coast Guard also is authorized to inspect vessels at will.
We are required by various governmental and quasi-governmental agencies to
obtain various permits, licenses and certificates with respect to our
operations. We believe that we have obtained or can obtain all permits, licenses
and certificates necessary for the conduct of our business.
In addition, we depend on the demand for our services from the oil and gas
industry and, therefore, our business is affected by laws and regulations, as
well as changing taxes and policies relating to the oil and gas industry
generally. In particular, the development and operation of oil and gas
properties located on the OCS of the United States is regulated primarily by the
MMS.
The MMS requires lessees of OCS properties to post bonds in connection with
the plugging and abandonment of wells located offshore and the removal of all
production facilities. Operators on the OCS are currently required to post an
area-wide bond of $3.0 million, or $500,000 per producing lease. We currently
have bonded our offshore leases as required by the MMS. Under certain
circumstances, the MMS has the authority to suspend or terminate operations on
federal leases. Any such suspensions or terminations of our operations could
have a material adverse effect on our financial condition and results of
operations.
10
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, or
OCSLA. These MMS directives are subject to change. The MMS has promulgated
regulations requiring offshore production facilities located on the OCS to meet
stringent engineering and construction specifications. The MMS also has issued
regulations restricting the flaring or venting of natural gas and prohibiting
the burning of liquid hydrocarbons without prior authorization. Similarly, the
MMS has promulgated other regulations governing the plugging and abandonment of
wells located offshore and the removal of all production facilities. Finally,
under certain circumstances, the MMS may require any operations on federal
leases to be suspended or terminated. In December 1999, the MMS issued
regulations that would allow it to expel unsafe operators from existing OCS
platforms and bar them from obtaining future leases.
Under OCSLA and the Federal Oil and Gas Royalty Management Act, MMS also
administers oil and gas leases and establishes regulations that set the basis
for royalties on oil and gas produced from the leases. The MMS amends these
regulations from time to time. For example, on March 15, 2000, the MMS issued a
final rule governing the calculation of royalties and the valuation of crude oil
produced from federal leases. The rule modifies the valuation procedures for
both arm's length and non-arm's length crude oil transactions to decrease
reliance on oil posted prices and assign a value to crude oil that better
reflects market value. The rule has been challenged by two industry trade
associations and is currently under judicial review in the United States
District Court for the District of Columbia. In addition, the MMS recently
issued a final rule amending its regulations regarding costs for natural gas
transportation that are deductible for royalty valuation purposes when natural
gas is sold off-lease. Among other matters, for purposes of computing royalties
owed, the rule disallows as deductions certain costs, such as
aggregator/marketer fees and transportation imbalance charges and associated
penalties. A United States District Court enjoined substantial portions of this
rule on March 28, 2000. The United States appealed the district court decision.
On February 8, 2002, the Court of Appeals for the District of Columbia reversed
the District Court and reinstated the regulations. The United States Supreme
Court denied the trade associations' petition for review on January 13, 2003.
Historically, the transportation and sale for resale of natural gas in
interstate commerce has been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978, or NGPA, and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission, or FERC. In the past,
the federal government has regulated the prices at which oil and gas could be
sold. While sales by producers of natural gas, and all sales of crude oil,
condensate and natural gas liquids currently can be made at uncontrolled market
prices, Congress could reenact price controls in the future. Deregulation of
wellhead sales in the natural gas industry began with the enactment of the NGPA.
In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended
the NGPA to remove both price and non-price controls from natural gas sold in
"first sales" no later than January 1, 1993.
Sales of natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation remain
subject to extensive federal and state regulation. Several major regulatory
changes have been implemented by Congress and the FERC from 1985 to the present
that affect the economics of natural gas production, transportation and sales.
In addition, the FERC continues to promulgate revisions to various aspects of
the rules and regulations affecting those segments of the natural gas industry,
most notably interstate natural gas transmission companies that remain subject
to FERC jurisdiction. These initiatives may also affect the intrastate
transportation of natural gas under certain circumstances. The stated purpose of
many of these regulatory changes is to promote competition among the various
sectors of the natural gas industry. The ultimate impact of the complex rules
and regulations issued by the FERC since 1985 cannot be predicted.
We cannot predict what further action the FERC will take on these matters,
but we do not believe any such action will materially affect us differently than
other companies with which we compete.
Additional proposals and proceedings before various federal and state
regulatory agencies and the courts could affect the 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
11
regulatory approach currently pursued by the FERC will continue indefinitely.
Notwithstanding the foregoing, we do not anticipate that compliance with
existing federal, state and local laws, rules and regulations will have a
material effect upon our capital expenditures, earnings or competitive position.
ENVIRONMENTAL REGULATION
Our operations are subject to a variety of national (including federal,
state and local) and international laws and regulations governing the discharge
of materials into the environment or otherwise relating to environmental
protection. Numerous governmental departments issue rules and regulations to
implement and enforce such laws that are often complex and costly to comply with
and that carry substantial administrative, civil and possibly criminal penalties
for failure to comply. Under these laws and regulations, we may be liable for
remediation or removal costs, damages and other costs associated with releases
of hazardous materials including oil into the environment, and such liability
may be imposed on us even if the acts that resulted in the releases were in
compliance with all applicable laws at the time such acts were performed. Some
of the environmental laws and regulations that are applicable to our business
operations are discussed in the following paragraphs, but the discussion does
not cover all environmental laws and regulations that govern our operations.
The Oil Pollution Act of 1990, as amended, or OPA, imposes a variety of
requirements on "responsible parties" related to the prevention of oil spills
and liability for damages resulting from such spills in waters of the United
States. A "Responsible Party" includes the owner or operator of an onshore
facility, a vessel or a pipeline, and the lessee or permittee of the area in
which an offshore facility is located. OPA imposes liability on each Responsible
Party for oil spill removal costs and for other public and private damages from
oil spills. Failure to comply with OPA may result in the assessment of civil and
criminal penalties. OPA establishes liability limits of $350 million for onshore
facilities, all removal costs plus $75 million for offshore facilities and the
greater of $500,000 or $600 per gross ton for vessels other than tank vessels.
The liability limits are not applicable, however, if the spill is caused by
gross negligence or willful misconduct; if the spill results from violation of a
federal safety, construction, or operating regulation; or if a party fails to
report a spill or fails to cooperate fully in the cleanup. Few defenses exist to
the liability imposed under OPA. Management is currently unaware of any oil
spills for which we have been designated as a Responsible Party under OPA that
will have a material adverse impact on us or our operations.
OPA also imposes ongoing requirements on a Responsible Party, including
preparation of an oil spill contingency plan and maintaining proof of financial
responsibility to cover a majority of the costs in a potential spill. We believe
we have appropriate spill contingency plans in place. With respect to financial
responsibility, OPA requires the Responsible Party for certain offshore
facilities to demonstrate financial responsibility of not less than $35 million,
with the financial responsibility requirement potentially increasing up to $150
million if the risk posed by the quantity or quality of oil that is explored for
or produced indicates that a greater amount is required. The MMS has promulgated
regulations implementing these financial responsibility requirements for covered
offshore facilities. Under the MMS regulations, the amount of financial
responsibility required for an offshore facility is increased above the minimum
amounts if the "worst case" oil spill volume calculated for the facility exceeds
certain limits established in the regulations. We believe that we currently have
established adequate proof of financial responsibility for our onshore and
offshore facilities and that we satisfy the MMS requirements for financial
responsibility under OPA and applicable regulations.
OPA also requires owners and operators of vessels over 300 gross tons to
provide the Coast Guard with evidence of financial responsibility to cover the
cost of cleaning up oil spills from such vessels. We currently own and operate
six vessels over 300 gross tons. Satisfactory evidence of financial
responsibility has been provided to the Coast Guard for all of our vessels.
The Clean Water Act imposes strict controls on the discharge of pollutants
into the navigable waters of the U.S. and imposes potential liability for the
costs of remediating releases of petroleum and other substances. The controls
and restrictions imposed under the Clean Water Act have become more stringent
over time, and it is possible that additional restrictions will be imposed in
the future. Permits must be obtained to discharge pollutants into state and
federal waters. Certain state regulations and the general permits issued
12
under the Federal National Pollutant Discharge Elimination System program
prohibit the discharge of produced waters and sand, drilling fluids, drill
cuttings and certain other substances related to the exploration for and
production of oil and gas into certain coastal and offshore waters. The Clean
Water Act provides for civil, criminal and administrative penalties for any
unauthorized discharge of oil and other hazardous substances and imposes
liability on responsible parties for the costs of cleaning up any environmental
contamination caused by the release of a hazardous substance and for natural
resource damages resulting from the release. Many states have laws that are
analogous to the Clean Water Act and also require remediation of releases of
petroleum and other hazardous substances in state waters. Our vessels routinely
transport diesel fuel to offshore rigs and platforms and also carry diesel fuel
for their own use. Our supply boats transport bulk chemical materials used in
drilling activities and also transport liquid mud which contains oil and oil by-
products. Offshore facilities and vessels operated by us have facility and
vessel response plans to deal with potential spills of oil or its derivatives.
We believe that our operations comply in all material respects with the
requirements of the Clean Water Act and state statutes enacted to control water
pollution.
OCSLA provides the federal government with broad discretion in regulating
the production of offshore resources of oil and gas, including authority to
impose safety and environmental protection requirements applicable to lessees
and permittees operating in the OCS. Specific design and operational standards
may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations
of lease conditions or regulations issued pursuant to OCSLA can result in
substantial civil and criminal penalties, as well as potential court injunctions
curtailing operations and cancellation of leases. Because our operations rely on
offshore oil and gas exploration and production, if the government were to
exercise its authority under OCSLA to restrict the availability of offshore oil
and gas leases, such action could have a material adverse effect on our
financial condition and results of operations. As of this date, we believe we
are not the subject of any civil or criminal enforcement actions under OCSLA.
The Comprehensive Environmental Response, Compensation, and Liability Act,
or CERCLA, contains provisions requiring the remediation of releases of
hazardous substances into the environment and imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
including owners and operators of contaminated sites where the release occurred
and those companies who transport, dispose of or who arrange for disposal of
hazardous substances released at the sites. Under CERCLA, such persons may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages
to natural resources and for the costs of certain health 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.
We operate in foreign jurisdictions that have various types of governmental
laws and regulations relating to the discharge of oil or hazardous substances
and the protection of the environment. Pursuant to these laws and regulations,
we could be held liable for remediation of some types of pollution, including
the release of oil, hazardous substances and debris from production, refining or
industrial facilities, as well as other assets we own or operate or which are
owned or operated by either our customers or our sub-contractors.
Management believes that we are in compliance in all material respects with
all applicable environmental laws and regulations to which we are subject. We do
not anticipate that compliance with existing environmental laws and regulations
will have a material effect upon our capital expenditures, earnings or
competitive position. However, changes in the environmental laws and
regulations, or claims for damages to persons, property, natural resources or
the environment, could result in substantial costs and liabilities, and thus
there can be no assurance that we will not incur significant environmental
compliance costs in the future.
EMPLOYEES
We rely on the high quality of our workforce. As of December 31, 2002, we
had 1,184 employees, 227 of which were salaried. As of that date we also
utilized approximately 450 non-U.S. citizens to crew our foreign flag vessels
under a crewing contract with C-MAR Services (UK), Ltd. of Aberdeen, Scotland.
None of our employees belong to a union or are employed pursuant to any
collective bargaining agreement or any similar arrangement. We believe that our
relationship with our employees and foreign crew members is good.
13
FACTORS INFLUENCING FUTURE RESULTS AND
ACCURACY OF FORWARD-LOOKING STATEMENTS
Shareholders should carefully consider the following risk factors in
addition to the other information contained herein. This Annual Report on Form
10-K includes certain statements that may be deemed "forward-looking statements"
within the meaning of Section 27A of the Securities Act and Section 21E of the
Exchange Act. You can identify these statements by forward-looking words such as
"anticipate," "believe," "budget," "could," "estimate," "expect," "forecast,"
"intend," "may," "plan," "potential," "should," "will" and "would' or similar
words. You should read statements that contain these words carefully because
they discuss our future expectations, contain projections of our future
financial position or results of operations or state other forward-looking
information. We believe that it is important to communicate our future
expectations to our investors. However, there may be events in the future that
we are not able to predict or control accurately. The factors listed below in
this section, captioned "Factors Influencing Future Results and Accuracy of
Forward-Looking Statements," as well as any cautionary language in this Annual
Report, provide examples of risks, uncertainties and events that may cause our
actual results to differ materially from the expectations we describe in our
forward-looking statements. You should be aware that the occurrence of the
events described in these risk factors and elsewhere in this Annual Report could
have a material adverse effect on our business, results of operations and
financial position.
OUR BUSINESS IS ADVERSELY AFFECTED BY LOW OIL AND GAS PRICES AND BY THE
CYCLICALITY OF THE OIL AND GAS INDUSTRY.
Our business is substantially dependent upon the condition of the oil and
gas industry and, in particular, the willingness of oil and gas companies to
make capital expenditures for offshore exploration, drilling and production
operations. The level of capital expenditures generally depends on the
prevailing view of future oil and gas prices, which are influenced by numerous
factors affecting the supply and demand for oil and gas, including, but not
limited to:
- Worldwide economic activity,
- Economic and political conditions in the Middle East and other
oil-producing regions,
- Coordination by the Organization of Petroleum Exporting Countries, or
OPEC,
- The cost of exploring for and producing oil and gas,
- The sale and expiration dates of offshore leases in the United States and
overseas,
- The discovery rate of new oil and gas reserves in offshore areas,
- Technological advances,
- Interest rates and the cost of capital,
- Environmental regulations, and
- Tax policies.
The level of offshore construction activity did not increase despite higher
commodity prices in 2002. We cannot assure you that activity levels will
increase anytime soon. A sustained period of low drilling and production
activity or the return of lower commodity prices would likely have a material
adverse effect on our financial position and results of operations.
THE OPERATION OF MARINE VESSELS IS RISKY, AND WE DO NOT HAVE INSURANCE COVERAGE
FOR ALL RISKS.
Marine construction involves a high degree of operational risk. Hazards,
such as vessels sinking, grounding, colliding and sustaining damage from severe
weather conditions, are inherent in marine operations. These hazards can cause
personal injury or loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.
Damage arising from such occurrences may result in lawsuits asserting large
claims. We maintain such insurance protection as we deem
14
prudent, including Jones Act employee coverage, which is the maritime equivalent
of workers' compensation, and hull insurance on our vessels. We cannot assure
you that any such insurance will be sufficient or effective under all
circumstances or against all hazards to which we may be subject. A successful
claim for which we are not fully insured could have a material adverse effect on
us. Moreover, we cannot assure you that we will be able to maintain adequate
insurance in the future at rates that we consider reasonable. As a result of
market conditions, premiums and deductibles for certain of our insurance
policies have increased substantially, and could escalate further. In some
instances, certain insurance could become unavailable or available only for
reduced amounts of coverage. For example, insurance carriers are now requiring
broad exclusions for losses due to war risk and terrorist acts. As construction
activity expands into deeper water in the Gulf, a greater percentage of our
revenues may be from Deepwater construction projects that are larger and more
complex, and thus riskier, than shallow water projects. As a result, our
revenues and profits are increasingly dependent on our larger vessels. The
current insurance on our vessels, in some cases, is in amounts approximating
book value, which is less than replacement value. In the event of property loss
due to a catastrophic marine disaster, mechanical failure or collision,
insurance may not cover a substantial loss of revenues, increased costs and
other liabilities, and could have a material adverse effect on our operating
performance if we were to lose any of our large vessels.
OUR CONTRACTING BUSINESS DECLINES IN WINTER, AND BAD WEATHER IN THE GULF OR
NORTH SEA CAN ADVERSELY AFFECT OUR OPERATIONS.
Marine operations conducted in the Gulf and North Sea are seasonal and
depend, in part, on weather conditions. Historically, we have enjoyed our
highest vessel utilization rates during the summer and fall when weather
conditions are favorable for offshore exploration, development and construction
activities. We typically have experienced our lowest utilization rates in the
first quarter. As is common in the industry, we typically bear the risk of
delays caused by some but not all adverse weather conditions. Accordingly, our
results in any one quarter are not necessarily indicative of annual results or
continuing trends.
IF WE BID TOO LOW ON A TURNKEY CONTRACT, WE SUFFER CONSEQUENCES.
A majority of our projects are performed on a qualified turnkey basis where
described work is delivered for a fixed price and extra work, which is subject
to customer approval, is billed separately. The revenue, cost and gross profit
realized on a turnkey contract can vary from the estimated amount because of
changes in offshore job conditions, variations in labor and equipment
productivity from the original estimates, and the performance of others such as
alliance partners. These variations and risks inherent in the marine
construction industry may result in our experiencing reduced profitability or
losses on projects.
ESTIMATES OF OUR OIL AND GAS RESERVES, FUTURE CASH FLOWS AND ABANDONMENT COSTS
MAY BE SIGNIFICANTLY INCORRECT.
Our proved reserves at December 31, 2002, included the reserves assigned to
our ownership position in the Gunnison project, a Deepwater Gulf of Mexico oil
and gas field operated by Kerr-McGee Corporation. These reserves constitute 47%
of our total proved reserves as of December 31, 2002. The reserves assigned to
Gunnison were not generated by our reservoir engineers, as we do not own the
seismic data for the three fields that comprise Gunnison. Instead, they were
determined based on information provided by the operator, Kerr-McGee Oil & Gas
Corporation. These reserve estimates were reviewed by our engineers, including
an assessment of the operator's assumptions and their engineering, geologic and
evaluation principles and techniques. This Annual Report also contains estimates
of our other proved oil and gas reserves and the estimated future net cash flows
therefrom based upon reports for the years ended December 31, 2000, 2001 and
2002, reviewed by Miller and Lents, Ltd., independent petroleum engineers. These
reports rely upon various assumptions, including assumptions required by the
Securities and Exchange Commission, as to oil and gas prices, drilling and
operating expenses, capital expenditures, abandonment costs, taxes and
availability of funds. The process of estimating oil and gas 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,
15
development expenditures, operating and abandonment expenses and quantities of
recoverable oil and gas reserves may vary substantially from those estimated in
these reports. Any significant variance in these assumptions could materially
affect the estimated quantity and value of our proved reserves. You should not
assume that the present value of future net cash flows from our proved reserves
referred to in this prospectus is the current market value of our estimated oil
and gas reserves. In accordance with Securities and Exchange Commission
requirements, we base the estimated discounted future net cash flows from our
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may differ materially from those used in the net present value
estimate. In addition, if costs of abandonment are materially greater than our
estimates, they could have an adverse effect on earnings.
THE GUNNISON PROJECT MAY NOT RESULT IN THE EXPECTED CASH FLOWS OR SUBSEA ASSET
UTILIZATION WE ANTICIPATE AND COULD INVOLVE SIGNIFICANT FUTURE CAPITAL OUTLAYS.
The Gunnison project is subject to a number of assumptions and
uncertainties, including estimates of the capital outlays necessary to develop
the prospect and the cash flows that we may ultimately derive. We cannot assure
you that we will be able to fund all required capital outlays or that these
outlays will be profitable. Moreover, although we have contracts for subsea
construction work, the extent of utilization of our subsea assets for such work
has not been fully determined. We have a $35.0 million loan facility to provide
for the financing of part of our portion of the construction costs of the spar,
of which we had drawn down $29.3 million as of December 31, 2002. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."
EXPECTED CASH FLOWS FROM THE Q4000, INTREPID AND SEAWELL, AS WELL AS CANYON, MAY
NOT BE IMMEDIATE OR AS HIGH AS EXPECTED.
The Q4000, Intrepid and the Seawell are vessels that were placed into
service during 2002. In addition, during 2002 we acquired Canyon Offshore, Inc.,
a supplier of ROVs to the offshore construction and telecommunications industry.
We will not receive any material increase in revenue or cash flow from their
operation until there is significant utilization of these vessels and Canyon's
services. We cannot assure you that customer demand for these vessels and
Canyon's services will be as high as currently anticipated and, as a result, our
future cash flows may be adversely affected. New vessels from third parties may
also enter the market in the coming years and compete with the Q4000, Intrepid
and the Seawell for contracts.
OUR OIL AND GAS OPERATIONS INVOLVE SIGNIFICANT RISKS, AND WE DO NOT HAVE
INSURANCE COVERAGE FOR ALL RISKS.
Our oil and gas operations are subject to risks incident to the operation
of oil and gas wells, including, but not limited to, uncontrollable flows of
oil, gas, brine or well fluids into the environment, blowouts, cratering,
mechanical difficulties, fires, explosions, pollution and other risks, any of
which could result in substantial losses to us. We maintain insurance against
some, but not all, of the risks described above.
WE MAY NOT BE ABLE TO COMPETE SUCCESSFULLY AGAINST CURRENT AND FUTURE
COMPETITORS.
The business in which we operate is highly competitive. Several of our
competitors are substantially larger and have greater financial and other
resources than we have. If other companies relocate or acquire vessels for
operations in the Gulf or the North Sea, levels of competition may increase and
our business could be adversely affected.
THE LOSS OF THE SERVICES OF ONE OR MORE OF OUR KEY EMPLOYEES, OR OUR FAILURE TO
ATTRACT AND RETAIN OTHER HIGHLY QUALIFIED PERSONNEL IN THE FUTURE, COULD DISRUPT
OUR OPERATIONS AND ADVERSELY AFFECT OUR FINANCIAL RESULTS.
Our industry has lost a significant number of experienced subsea people
over the years due to, among other reasons, the volatility in commodity prices.
Our continued success depends on the active participation of our key employees.
The loss of our key people could adversely affect our operations. We believe
that our
16
success and continued growth are also dependent upon our ability to attract and
retain skilled personnel. We believe that our wage rates are competitive;
however, unionization or a significant increase in the wages paid by other
employers could result in a reduction in our workforce, increases in the wage
rates we pay, or both. If either of these events occurs for any significant
period of time, our revenues and profitability could be diminished and our
growth potential could be impaired.
IF WE FAIL TO EFFECTIVELY MANAGE OUR GROWTH, OUR RESULTS OF OPERATIONS COULD BE
HARMED.
We have a history of growing through acquisitions of large assets and
acquisitions of companies. We must plan and manage our acquisitions effectively
to achieve revenue growth and maintain profitability in our evolving market. If
we fail to effectively manage current and future acquisitions, our results of
operations could be adversely affected. Our growth has placed, and is expected
to continue to place, significant demands on our personnel, management and other
resources. We must continue to improve our operational, financial, management
and legal/compliance information systems to keep pace with the growth of our
business.
WE MAY NEED TO CHANGE THE MANNER IN WHICH WE CONDUCT OUR BUSINESS IN RESPONSE TO
CHANGES IN GOVERNMENT REGULATIONS.
Our subsea construction, intervention, inspection, maintenance and
decommissioning operations and our oil and gas 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 to comply
with, and significant fines and penalties may be imposed for noncompliance. We
cannot assure you that continued compliance with existing or future laws or
regulations will not adversely affect our operations.
CERTAIN PROVISIONS OF OUR CORPORATE DOCUMENTS AND MINNESOTA LAW MAY DISCOURAGE A
THIRD PARTY FROM MAKING A TAKEOVER PROPOSAL.
In addition to the 55,000 shares of preferred stock issued or issuable to
Fletcher International, Ltd. under the First Amended and Restated Agreement
dated January 17, 2003, but effective as of December 31, 2002, by and between
Cal Dive and Fletcher International, Ltd., our board of directors has the
authority, without any action by our shareholders, to fix the rights and
preferences on up to 4,945,000 shares of undesignated preferred stock, including
dividend, liquidation and voting rights. In addition, our by-laws divide the
board of directors into three classes. We are also subject to certain
anti-takeover provisions of the Minnesota Business Corporation Act. We also have
employment contracts with all of our senior officers that require cash payments
in the event of a "change of control." Any or all of the provisions or factors
described above may have the effect of discouraging a takeover proposal or
tender offer not approved by management and the board of directors and could
result in shareholders who may wish to participate in such a proposal or tender
offer receiving less for their shares than otherwise might be available in the
event of a takeover attempt.
ITEM 2. PROPERTIES
OUR VESSELS
We own a fleet of 22 vessels and 21 ROVs and trenchers. We believe that the
Gulf market requires specially designed and/or equipped vessels to competitively
deliver subsea construction services. Nine of our vessels have DP capabilities
specifically designed to respond to the Deepwater market requirements. Eight of
our vessels (seven of which are based in the Gulf) have the capability to
provide saturation diving services. Recent developments in our fleet include:
Q4000: We began construction of our newest Ultra-Deepwater MSV, the
Q4000, in 1999, and accepted her delivery in early 2002. The vessel cost
$182 million and incorporates our latest semi-submersible technologies,
including various patented elements such as the absence of lower hull cross
bracing. A variable deck load of over 4,000 metric tons and upgraded well
completions capability make
17
the vessel particularly well suited for large offshore construction
projects in the Ultra-Deepwater. Its Huisman-Itrec multi-purpose tower has
an open face which allows free access from three sides, an advantage for a
construction and intervention vessel.
Intrepid: The Intrepid (formerly Sea Sorceress) offers customers a
pipelay/construction vessel capable of carrying an 8,000 metric ton deck
load. She began work in June of 2002.
Eclipse: This large DP DSV is 370 feet long, 67 feet wide and has
recently been refitted into a DSV by installing a saturation diving system,
restoring the ballast system and upgrading to DP-2. The Eclipse began work
in March 2002.
Seawell: This purpose-built 364 foot mono-hull DP vessel, capable of
supporting both manned diving and ROVs, was recently upgraded for coiled
tubing deployment and well testing. The Seawell was purchased in July 2002.
Northern Canyon: Canyon took delivery of this purpose-built, 270 foot
state-of-the-art ROV support vessel in July 2002. The vessel, which is
deployed in the North Sea, is leased from a third party.
ROVs: To enable us to control critical path equipment involved in our
deepwater projects, we acquired Canyon in January 2002. Canyon currently
operates 17 ROVs and four trencher systems. In 2001, Canyon introduced the
next-generation work-class ROV, the Quest. Advantages of the Quest include:
electric instead of hydraulic systems, 50% smaller footprint, fewer moving
parts (i.e., lower operating costs), a dynamic positioning system and
improved depth rating. The average age of the Canyon ROV fleet is
approximately two years. Furthermore, Canyon has ordered three new Triton
XLS ROV systems and a state of the art 750 horsepower trenching unit to
fulfill its future contract obligations under its agreement with Technip.
18
LISTING OF VESSELS, BARGE AND ROVS
DATE MOONPOOL FOUR
CAL DIVE CLEAR DECK DECK LAUNCH/ POINT CRANE
PLACED IN LENGTH SPACE (SQ. LOAD SAT ANCHOR CAPACITY
SERVICE (FEET) FEET) (TONS) BERTHS DIVING MOORED (TONS) CLASSIFICATION(1)
--------- ------ ---------- ------ ------ -------- ------ ------------ -----------------
DP MSVS:
Uncle John......... 11/96 254 11,834 460 102 X -- 2 X 100 DNV
Q4000(2)........... 4/02 310 26,400 4,000 138 X -- 160; 350; ABS
Derrick: 600
FLOWLINE LAY:
Intrepid(4)........ 8/97 374 17,730 8,000 50 -- -- 440 DNV
WELL OPERATIONS:
Seawell(6)......... 7/02 368 900 700 129 X -- 130 DNV
DP DSVS:
Eclipse(5)......... 3/02 380 8,611 2,436 109 X -- A-Frame DNV
Witch Queen........ 11/95 278 5,600 500 60 X -- 50 DNV
Mystic Viking...... 6/01 253 5,600 1,340 60 X -- 50 DNV
DP ROV SUPPORT
Vessels:
Merlin............. 12/97 198 955 308 42 -- -- A-Frame ABS
Northern
Canyon(3)........ 2002 276 9,677 2,400 60 -- -- 50 DNV
DSVS:
Cal Diver I........ 7/84 196 2,400 220 40 X X 20 ABS
Cal Diver II....... 6/85 166 2,816 300 32 X X A-Frame ABS
Cal Diver V........ 9/91 168 2,324 490 30 -- X A-Frame ABS
Cal Diver IV....... 3/01 120 1,440 60 24 -- -- -- ABS
Mr. Fred........... 3/00 167 2,465 500 36 -- X 25 USCG
Mr. Sonny(7)....... 3/01 175 3,480 409 28 -- X 35 ABS
UTILITY VESSELS:
Mr. Jim............ 2/98 110 1,210 64 19 -- -- -- USCG
Mr. Jack........... 1/98 120 1,220 66 22 -- -- -- USCG
Polo Pony(7)....... 3/01 110 1,240 69 25 -- -- -- ABS
Sterling Pony(7)... 3/01 110 1,240 64 25 -- -- -- ABS
White Pony(7)...... 3/01 116 1,230 64 25 -- -- -- ABS
OTHER:
Cal Dive Barge I... 8/90 150 N/A 200 26 -- X 200 ABS
Talisman........... 11/00 195 3,000 675 15 -- -- -- ABS
21 ROVs and
trenchers(8)..... Various(4) -- -- -- -- -- -- -- --
---------------
(1) Under government regulations and our insurance policies, we are required to
maintain our vessels in accordance with standards of seaworthiness and
safety set by government regulations and classification organizations. We
maintain our fleet to the standards for seaworthiness, safety and health set
by the American Bureau of Shipping, or ABS, Det Norske Veritas, or DNV, and
the U.S. Coast Guard, or USCG. The ABS is one of several classification
societies used by ship owners to certify that their vessels meet certain
structural, mechanical and safety equipment standards, including Lloyd's
Register, Bureau Veritas and DNV among others.
(2) The Q4000 commenced work in April 2002.
(3) This leased vessel became available in June 2002.
(4) The Intrepid modifications were completed in May 2002 and the vessel began
work in June 2002.
19
(5) The Eclipse was purchased in October 2001 and began work in March 2002.
(6) The Seawell was purchased and began work in July 2002.
(7) In March 2001, we acquired substantially all of the assets of Professional
Divers including the Mr. Sonny (a 165-foot four-point moored DSV), three
utility vessels and associated diving equipment including two saturation
diving systems.
(8) Average age of ROV fleet is two years.
We incur routine drydock inspection, maintenance and repair costs pursuant
to Coast Guard regulations and in order to maintain ABS or DNV classification
for our vessels. In addition to complying with these requirements, we have our
own vessel maintenance program that we believe permits us to continue to provide
our customers with well maintained, reliable vessels. In the normal course of
business, we charter other vessels on a short-term basis, such as tugboats,
cargo barges, utility boats and dive support vessels. All of our vessels are
subject to ship mortgages to secure our $70.0 million revolving credit facility,
except the Northern Canyon (leased),and the Q4000 (subject to liens to secure
the MARAD financing guarantees).
SUMMARY OF NATURAL GAS AND OIL RESERVE DATA
The table below sets forth information, as of December 31, 2002, with
respect to estimates of net proved reserves and the present value of estimated
future net cash flows at such date, prepared in accordance with guidelines
established by the Securities and Exchange Commission. The Company's estimates
of reserves at December 31, 2002, excluding Gunnison, have been reviewed by
Miller and Lents, Ltd., independent petroleum engineers. These non-Gunnison
reserves totaled (as of December 31, 2002) 43,323 MMcf of natural gas and 6,727
MBbls of oil with a standardized measure of discounted future net cash flows
(pre-tax) of $161,565,600 (see note (2) in table below). Since the Company does
not own a license to the geophysical data, reserves attributable to Gunnison
(which total 47% of the proved reserves as of December 31, 2002) have been
determined based on information provided by the operator. These reserve
estimates were reviewed by our engineers, including an assessment of the
operator's assumptions and their engineering, geologic and evaluation principles
and techniques. All of the Company's reserves are located in the United States.
Proved reserves cannot 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.
TOTAL PROVED
------------
Estimated Proved Reserves(1):
Natural gas (MMcf)........................................ 85,224
Oil and condensate (MBbls)................................ 12,037
Standardized measure of discounted future net cash flows
(pre-tax)(2).............................................. $291,705,010
---------------
(1) Includes both Company's reserves reviewed by Miller & Lents (as noted above)
and Gunnison reserves reviewed by Company's engineers.
(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 December 31, 2002, we owned an interest
in 157 gross (105 net) natural gas wells and 302 gross (265 net) oil wells
located in federal and state offshore waters in the Gulf of Mexico.
20
FACILITIES
Our corporate headquarters are located at 400 N. Sam Houston Parkway E.,
Suite 400, Houston, Texas. Our primary subsea and marine services operations are
based in Morgan City, Louisiana. All of our facilities are leased.
PROPERTIES AND FACILITIES SUMMARY
FUNCTION SIZE
-------- ----
Houston, Texas......................... Cal Dive International , Inc. 37,800 square feet
(CDI)
Corporate Headquarters, Project
Management, and Sales Office;
Energy Resource Technology, Inc.; 15,000 square feet
and Well Ops Inc.
Canyon Corporate Headquarters,
Management and Sales Office
Aberdeen, Scotland..................... Canyon Sales Office 12,000 square feet
Well Ops (U.K.) Limited Operations 4,600 square feet
Singapore.............................. Canyon Operations 10,000 square feet
Morgan City, Louisiana................. CDI Operations 28.5 acres
CDI Warehouse 30,000 square feet
CDI Offices 4,500 square feet
Lafayette, Louisiana................... Aquatica Operations 8 acres
Aquatica Warehouse 12,000 square feet
Aquatica Offices 5,500 square feet
New Orleans, Louisiana................. Aquatica Sales Office 2,724 square feet
ITEM 3. LEGAL PROCEEDINGS
INSURANCE AND LITIGATION
Our operations are subject to the inherent risks of offshore marine
activity, including accidents resulting in personal injury and the loss of life
or property, environmental mishaps, mechanical failures, fires and collisions.
We insure against these risks at levels consistent with industry standards. We
also carry workers' compensation, maritime employer's liability, general
liability and other insurance customary in our business. All insurance is
carried at levels of coverage and deductibles that we consider financially
prudent. Our services are provided in hazardous environments where accidents
involving catastrophic damage or loss of life could occur, and litigation
arising from such an event may result in our being named a defendant in lawsuits
asserting large claims. To date, we have been involved in only one such claim,
where the cost of our vessel, the Balmoral Sea, was fully covered by insurance.
Although there can be no assurance that the amount of insurance we carry is
sufficient to protect us fully in all events, or that such insurance will
continue to be available at current levels of cost or coverage, we believe that
our insurance protection is adequate for our business operations. A successful
liability claim for which we are underinsured or uninsured could have a material
adverse effect on our business.
We are involved in various legal proceedings, primarily involving claims
for personal injury under the General Maritime Laws of the United States and the
Jones Act as a result of alleged negligence. In addition, we from time to time
incur other claims, such as contract disputes, in the normal course of business.
In that regard, in 1998, one of our subsidiaries entered into a subcontract with
Seacore Marine Contractors Limited ("Seacore") to provide the Sea Sorceress to a
Coflexip subsidiary in Canada ("Coflexip"). Due to difficulties with respect to
the sea states and soil conditions the contract was terminated and an
arbitration to recover damages was commenced. A preliminary liability finding
has been made by the arbitrator against Seacore and in favor of the Coflexip
subsidiary. We were not a party to this arbitration proceeding. Seacore and
Coflexip
21
settled this matter prior to the conclusion of the arbitration proceeding with
Seacore paying Coflexip $6.95 million CDN. Seacore has now made demand on Cal
Dive Offshore Ltd. ("CDO"), a subsidiary of Cal Dive, for one-half of this
amount. Because only one of the grounds in the preliminary findings by the
arbitrator is applicable to CDO, and because CDO holds substantial counterclaims
against Seacore, management believes that in the event Seacore continues to seek
contribution from our subsidiary, which would require another arbitration, it is
anticipated that our subsidiary's exposure, if any, should be less than
$500,000.
During 2002, the Company engaged in a large construction project and, in
late September, supports engineered by a subcontractor failed resulting in over
a month of downtime for two of CDI's vessels. Management believes that under the
terms of the contract the Company is entitled to the contractual stand-by rate
for the vessels during their downtime. The customer is currently disputing these
invoices along with certain other change orders. Of the amounts billed by CDI
for this project, $12.1 million had not been collected as of February 18, 2003.
Due to the size of the dispute, inherent uncertainties with respect to a
mediation and relationship issues with the customer, CDI provided a reserve in
the fourth quarter of 2002 resulting in a loss for the Company on the project as
a whole. In another lengthy commercial dispute, EEX Corporation sued Cal Dive
and others alleging breach of fiduciary duty by a former EEX employee and
damages resulting from certain construction and property acquisition agreements.
Cal Dive had responded alleging EEX Corporation breached various provisions of
the same contracts. EEX's acquisition by Newfield during the fourth quarter 2002
enabled CDI to enter meaningful settlement discussions prior to the trial date,
which was set for February 2003. This resulted in a settlement including CDI
making a cash payment, subsequent to yearend, and agreeing to provide work
credits for its services over the next three years. The total value of the
settlement was recorded in the Company's statement of operations for the year
ended December 31, 2002. This settlement combined with the reserves on the
project discussed above resulted in approximately $10 million of pre-tax charges
recorded in the accompanying statement of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
ITEM (UNNUMBERED). EXECUTIVE OFFICERS OF THE COMPANY
The executive officers of Cal Dive are as follows:
NAME AGE POSITION
---- --- --------
Owen Kratz................................ 48 Chairman and Chief Executive Officer
and Director
Martin R. Ferron.......................... 46 President and Chief Operating Officer
and Director
S. James Nelson, Jr....................... 61 Vice Chairman and Director
James Lewis Connor, III................... 45 Senior Vice President, General Counsel
and Corporate Secretary
A. Wade Pursell........................... 38 Senior Vice President, Chief Financial
Officer and Treasurer
Johnny Edwards............................ 49 President -- Energy Resource
Technology, Inc.
Owen Kratz is Chairman and Chief Executive Officer of Cal Dive
International, Inc. He was appointed Chairman in May 1998 and has served as our
Chief Executive Officer since April 1997. Mr. Kratz served as President from
1993 until February 1999, and as a Director since 1990. He served as Chief
Operating Officer from 1990 through 1997. Mr. Kratz joined Cal Dive in 1984 and
has held various offshore positions, including saturation diving supervisor, and
has had management responsibility for client relations, marketing and
estimating. From 1982 to 1983, Mr. Kratz was the owner of an independent marine
construction company operating in the Bay of Campeche. Prior to 1982, he was a
superintendent for Santa Fe and various international diving companies, and a
saturation diver in the North Sea.
22
Martin R. Ferron has served on our board of directors since September 1998.
Mr. Ferron became President in February 1999 and has served as Chief Operating
Officer since January 1998. Mr. Ferron has 20 years of experience in the
oilfield industry, including seven in senior management positions with the
international operations of McDermott Marine Construction and Oceaneering
International Services, Limited. Mr. Ferron has a civil engineering degree, a
master's degree in marine technology, an MBA and is a chartered civil engineer.
S. James Nelson, Jr. is Vice Chairman and has been a Director of Cal Dive
since 1990. Prior to October 2000, he was Executive Vice President and Chief
Financial Officer. From 1985 to 1988, Mr. Nelson was the Senior Vice President
and Chief Financial Officer of Diversified Energies, Inc., the former parent of
Cal Dive, at which time he had corporate responsibility for Cal Dive. From 1980
to 1985, Mr. Nelson served as Chief Financial Officer of Apache Corporation, an
oil and gas exploration and production company. From 1966 to 1980, Mr. Nelson
was employed with Arthur Andersen & Co., and, from 1976 to 1980, he was a
partner serving on the firm's worldwide oil and gas industry team. Mr. Nelson
received an undergraduate degree from Holy Cross College (B.S.) and an MBA from
Harvard University; he is also a Certified Public Accountant.
James Lewis Connor, III became Senior Vice President and General Counsel of
Cal Dive in May 2002 and Corporate Secretary in July 2002. He had previously
served as Deputy General Counsel since May 2000. Mr. Connor has been involved
with the oil and gas industry for nearly 20 years, including 11 years in his
capacity as legal counsel to both companies and individuals. Prior to joining
Cal Dive, Mr. Connor was a Senior Counsel at El Paso Production Company
(formerly Sonat Exploration Company) from 1997 to 2000 and previously from 1995
to 1997 was a senior associate in the oil, gas and energy law section of
Hutcheson & Grundy, L.L.P. Mr. Connor received his Bachelor of Science degree
from Texas A&M University in 1979 and his law degree, with honors, from the
University of Houston in 1991.
A. Wade Pursell is Senior Vice President and Chief Financial Officer of Cal
Dive International, Inc. In this capacity, which he was appointed to in October
2000, Mr. Pursell oversees the treasury, accounting, information technology,
tax, administration and corporate planning functions. He joined Cal Dive in May
1997, as Vice President -- Finance and Chief Accounting Officer. From 1988
through 1997 he was with Arthur Andersen LLP, lastly as an Experienced Manager
specializing in the offshore services industry (which included servicing the Cal
Dive account from 1990 to 1997). Mr. Pursell received an undergraduate degree
(B.S.) from the University of Central Arkansas and is a Certified Public
Accountant.
Johnny Edwards has been President of ERT since March 2000. He joined ERT in
1994 as Engineering and Acquisitions Manager, where he has been instrumental in
the growth of the company. Prior to joining ERT, Mr. Edwards worked for ARCO Oil
& Gas Company for 19 years and held various technical and management positions
in engineering and operations. Mr. Edwards received a Bachelor of Science degree
in Chemical Engineering from Louisiana Tech University in 1975.
23
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS
Our common stock is traded on the Nasdaq National Market under the symbol
"CDIS." The following table sets forth, for the periods indicated, the high and
low closing sale prices per share of our common stock:
COMMON STOCK
PRICE
---------------
HIGH LOW
------ ------
Calendar Year 2001
First quarter............................................. $31.00 $22.00
Second quarter............................................ 30.66 21.88
Third quarter............................................. 23.04 15.98
Fourth quarter............................................ 25.86 16.01
Calendar Year 2002
First quarter............................................. $25.20 $20.50
Second quarter............................................ $27.22 $21.70
Third quarter............................................. $21.90 $15.36
Fourth quarter............................................ $25.20 $20.00
Calendar Year 2003
First quarter (through March 17, 2003).................... $24.46 $16.99
On March 17, 2003, the closing sale price of our common stock on the Nasdaq
National Market was $18.64 per share. As of March 17, 2003, there were an
estimated 8,467 beneficial holders of our common stock.
On January 2, 2002, CDI purchased Canyon Offshore, Inc. for cash of $52.8
million, the assumption of $9.0 million of Canyon debt (offset by $3.1 million
of cash acquired), securities exchangeable for 181,000 shares of Cal Dive common
stock and a commitment to purchase the redeemable stock in Canyon for cash at a
price to be determined by Canyon's performance during the years 2002 through
2004 from continuing employees at a minimum purchase price of $13.53 per share.
The securities exchangeable for Cal Dive common stock were issued to certain
former shareholders of Canyon in reliance on the exemption from registration
provided by Section 4(2) of the Securities Act of 1933, as amended. The three
persons acquiring the securities exchangeable for Cal Dive common stock are
sophisticated investors who represented to Cal Dive that the securities were
being acquired for investment purposes and not with a view to distribution.
DIVIDEND POLICY
We have never declared or paid cash dividends on our common stock and do
not intend to pay cash dividends in the foreseeable future. We currently intend
to retain earnings, if any, for the future operation and growth of our business.
In addition, our financing arrangements prohibit the payment of cash dividends
on our common stock. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."
ITEM 6. SELECTED FINANCIAL DATA
The financial data presented below for each of the five years ended
December 31, 2002, should be read in conjunction with Management's Discussion
and Analysis of Financial Condition and Results of Operations
24
and the Consolidated Financial Statements and Notes to Consolidated Financial
Statements included elsewhere in this Form 10-K (in thousands, except per share
amounts).
1998 1999 2000 2001 2002
-------- -------- -------- -------- --------
Net Revenues.................... $151,887 $160,054 $181,014 $227,141 $302,705
Gross Profit.................... 49,209 37,251 55,369 66,911 53,792
Net Income...................... 24,125 16,899 23,326 28,932 12,377
Net Income per share:
Basic......................... 0.83 0.56 0.74 0.89 0.35
Diluted....................... 0.81 0.55 0.72 0.88 0.35
Total Assets.................... 164,235 243,722 347,488 473,122 845,858
Long-Term Debt.................. -- -- 40,054 98,048 223,576
Shareholders' Equity............ 113,643 150,872 194,725 226,349 337,517
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
Oil and gas prices, the offshore mobile rig count, and Deepwater
construction activity are three of the primary indicators we use to forecast the
future performance of our business. Our construction services generally follow
successful drilling activities by six to eighteen months on the OCS and twelve
months or longer in the Deepwater arena. The level of drilling activity is
related to both short- and long-term trends in oil and gas prices. In the second
quarter of 1999, oil prices reached their highest levels since the First Gulf
War and natural gas prices reached $10.00 per Mcf in early 2001, pushing
offshore mobile rig utilization rates back to virtually full utilization.
However, a slowing world economy and record levels of natural gas in storage
resulted in significantly lower offshore mobile rig utilization rates in the
second half of 2001 and throughout 2002. Commodity prices have recently
recovered to very robust levels; however, with the instability in the Middle
East and a slow world economy, drilling activity has yet to respond. Our primary
leading indicator, the number of offshore mobile rigs contracted, is currently
at approximately 115 rigs employed in the Gulf of Mexico, compared to 182 during
the first quarter of 2001. The Deepwater Gulf is principally being developed for
oil, with the complexity of developing these reservoirs resulting in significant
lead times to first production.
Product prices impact our oil and gas operations in several respects. We
seek to acquire producing oil and gas properties that are generally in the later
stages of their economic life. The sellers' potential abandonment liabilities
are a significant consideration with respect to the offshore properties we have
purchased to date. Although higher natural gas prices tend to reduce the number
of mature properties available for sale, these higher prices typically
contribute to improved operating results for ERT. In contrast, lower natural gas
prices, typically contribute to lower operating results for ERT and a general
increase in the number of mature properties available for sale. We have expanded
the scope of our gas and oil operations by taking a working interest in
Gunnison, a Deepwater Gulf development of Kerr-McGee Oil & Gas Corporation which
has discovered significant reserves, and participating in the ownership of the
Marco Polo production facility.
Vessel utilization is historically lower during the first quarter due to
winter weather conditions in the Gulf and the North Sea. Accordingly, we plan
our drydock inspections and other routine and preventive maintenance programs
during this period. During the first quarter, a substantial number of our
customers finalize capital budgets and solicit bids for construction projects.
The bid and award process during the first two quarters typically leads to the
commencement of construction activities during the second and third quarters. As
a result, we have historically generated up to 65% of our marine contracting
revenues in the last six months of the year. Our operations can also be severely
impacted by weather during the fourth quarter. Our salvage barge, which has a
shallow draft, is particularly sensitive to adverse weather conditions, and its
utilization rate tends to be lower during such periods. Operation of oil and gas
properties and production facilities tends to offset the impact of weather since
the first and fourth quarters are typically periods of high demand and strong
prices for natural gas. Due to this seasonality, full year results are not
likely to be a direct multiple of any particular quarter or combination of
quarters.
26
The following table sets forth for the periods presented average U.S.
natural gas prices, our equivalent natural gas production, the average number of
offshore rigs under contract in the Gulf, the number of platforms installed and
removed in the Gulf and the vessel utilization rates for each of the major
categories of our fleet.
2002 2001 2002
----------------------------- ----------------------------- -----------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
U.S. natural gas prices(1)...... $2.52 $3.47 $4.27 $5.29 $7.09 $4.67 $2.88 $2.45 $2.19 $3.21 $3.00 $3.76
ERT oil and gas production
(MMcfe)....................... 3,321 4,169 4,271 3,725 4,290 3,552 3,289 2,797 2,910 3,487 3,967 6,230
Rigs under contract in the
Gulf(2)....................... 148 160 175 178 182 189 165 125 122 125 131 128
Platform installations(3)....... 9 19 27 19 12 19 20 11 14 19 14 11
Platform removals(3)............ -- 25 61 7 13 11 19 16 11 37 26 4
Our average vessel utilization
rate:(4)
DP............................ 71% 38% 45% 56% 61% 76% 85% 95% 74% 81% 71% 81%
Saturation DSV................ 57 57 78 60 72 67 82 91 45 68 75 89
Surface diving................ 31 58 55 57 61 81 72 60 58 62 47 66
Derrick barge................. 8 41 53 59 30 54 67 47 -- 46 52 38
---------------
(1) Average of the monthly Henry Hub cash prices per Mcf, as reported in Natural
Gas Week.
(2) Average monthly number of rigs contracted, as reported by Offshore Data
Services.
(3) Source: Offshore Data Services; installation and removal of platforms with
two or more piles in the Gulf.
(4) Average vessel utilization rate is calculated by dividing the total number
of days the vessels in this category generated revenues by the total number
of days in each quarter.
CRITICAL ACCOUNTING POLICIES
Our results of operations and financial condition, as reflected in the
accompanying financial statements and related footnotes, are subject to
management's evaluation and interpretation of business conditions, changing
capital market conditions and other factors which could affect the ongoing
viability of our business segments and/or our customers. We believe the most
critical accounting policies in this regard are the estimation of revenue
allowance on gross amounts billed and evaluation of recoverability of property
and equipment and goodwill balances. While these issues require us to make
judgments that are somewhat subjective, they are generally based on a
significant amount of historical data and current market data. Another area
which requires us to make subjective judgments is that of revenue recognition.
Our revenues are derived from billings under contracts, which are typically of
short duration, that provide for either lump-sum turnkey charges or specific
time, material and equipment charges which are billed in accordance with the
terms of such contracts. We recognize revenue as it is earned at estimated
collectible amounts. Revenue on significant turnkey contracts is recognized on
the percentage-of-completion method based on the ratio of costs incurred to
total estimated costs at completion. Contract price and cost estimates are
reviewed periodically as work progresses and adjustments are reflected in the
period in which such estimates are revised. Provisions for estimated losses on
such contracts are made in the period such losses are determined.
ERT acquisitions of producing offshore properties are recorded at the fair
value exchanged at closing together with an estimate of its proportionate share
of the undiscounted decommissioning liability assumed in the purchase based upon
its working interest ownership percentage. In estimating the decommissioning
liability assumed in offshore property acquisitions, we perform detailed
estimating procedures, including engineering studies. We follow the successful
efforts method of accounting for our interests in oil and gas properties. Under
the successful efforts method, the costs of successful wells and leases
containing productive reserves are capitalized. Costs incurred to drill and
equip development wells, including unsuccessful development wells, are
capitalized.
27
The Company also considers the following accounting policies to be the most
critical to the preparation of its financial statements:
GOODWILL AND INDEFINITE-LIVED INTANGIBLES
In accordance with SFAS No. 142, Goodwill and Indefinite-Lived Intangibles
("SFAS No. 142"), the Company tests for the impairment of goodwill and other
intangible assets with indefinite lives on at least an annual basis. The
Company's goodwill impairment test involves a comparison of the fair value of
each of the Company's reporting units, as defined under SFAS No. 142, with its
carrying amount. The Company's indefinite-lived asset impairment test involves a
comparison of the fair value of the intangible and its carrying value. The fair
value is determined using discounted cash flows and other market-related
valuation models, such as earnings multiples and comparable asset market values.
These tests are influenced significantly by management estimates of future cash
flows and the related expected utilization of assets. Prior to the adoption of
SFAS No. 142, goodwill was amortized on a straight line basis over 25 years. In
conjunction with the adoption of this statement, the Company has discontinued
the amortization of goodwill.
PROPERTY AND EQUIPMENT
Property and equipment, both owned and under capital leases, are recorded
at cost. Depreciation is provided primarily on the straight-line method over the
estimated useful lives of the assets.
In accordance with Statement of Financial Accounting Standards ("SFAS") No.
144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No.
144"), long-lived assets, excluding goodwill and indefinite-lived intangibles,
to be held and used by the Company are reviewed to determine whether any events
or changes in circumstances indicate that the carrying amount of the asset may
not be recoverable. SFAS No. 144 modifies SFAS No. 121, Accounting for the
Impairment or Disposal of Long-Lived Assets to be Disposed of ("SFAS No. 121").
For long-lived assets to be held and used, the Company bases its evaluation on
impairment indicators such as the nature of the assets, the future economic
benefit of the assets, any historical or future profitability measurements and
other external market conditions or factors that my be present. If such
impairment indicators are present or other factors exist that indicate that the
carrying amount of the asset may not be recoverable, the Company determines
whether an impairment has occurred through the use of an undiscounted cash flows
analysis of the asset at the lowest level for which identifiable cash flows
exist. If an impairment has occurred, the Company recognizes a loss for the
difference between the carrying amount and the fair value of the asset. The fair
value of the asset is measured using quoted market prices or, in the absence of
quoted market prices, is based on management's estimate of discounted cash
flows. Assets are classified as held for sale when the Company has a plan for
disposal of certain assets and those assets meet the held for sale criteria of
SFAS No. 144.
FOREIGN CURRENCY
The functional currency for the Company's foreign subsidiary Well Ops
(U.K.) Limited is the applicable local currency (British Pound). Results of
operations for this subsidiary are translated into U.S. dollars using average
exchange rates during the period. Assets and liabilities of this foreign
subsidiary are translated into U.S. dollars using the exchange rate in effect at
the balance sheet date and the resulting translation adjustment which was a gain
of $2.5 million, net of taxes, in 2002 is accumulated as a component of
shareholders' equity. All foreign currency transaction gains and losses are
recognized currently in the statements of operations.
Canyon Offshore, the Company's ROV subsidiary, has operations in the United
Kingdom and Southeast Asia sectors. Canyon conducts the majority of its affairs
in these regions in U.S. dollars which it considers the functional currency.
When currencies other than the U.S. dollar are to be paid or received the
resulting gain or loss from translation is recognized in the statements of
operations. These amounts for the year ended December 31, 2002 were not material
to the Company's results of operations or cash flows.
28
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES
The Company's price risk management activities involve the use of
derivative financial instruments to hedge the impact of market price risk
exposures primarily related to our oil and gas production. Under SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, all derivatives
are reflected in our balance sheet at their fair market value.
Under SFAS No. 133 there are two types of hedging activities: hedges of
cash flow exposure and hedges of fair value exposure. The Company engages
primarily in cash flow hedges. Hedges of cash flow exposure are entered into to
hedge a forecasted transaction or the variability of cash flows to be received
or paid related to a recognized asset or liability. Changes in the derivative
fair values that are designated as cash flow hedges are deferred to the extent
that they are effective and are recorded as a component of accumulated other
comprehensive income until the hedged transactions occur and are recognized in
earnings. The ineffective portion of a cash flow hedge's change in value is
recognized immediately in earnings in oil and gas production revenues.
As required by SFAS No. 133, we formally document all relationships between
hedging instruments and hedged items, as well as our risk management objectives,
strategies for undertaking various hedge transactions and our methods for
assessing and testing correlation and hedge ineffectiveness. All hedging
instruments are linked to the hedged asset, liability, firm commitment or
forecasted transaction. We also assess, both at the inception of the hedge and
on an on-going basis, whether the derivatives that are used in our hedging
transactions are highly effective in offsetting changes in cash flows of the
hedged items. We discontinue hedge accounting prospectively if we determine that
a derivative is no longer highly effective as a hedge.
The market value of hedging instruments reflects our best estimate and is
based upon exchange or over-the-counter quotations whenever they are available.
Quoted valuations may not be available due to location differences or terms that
extend beyond the period for which quotations are available. Where quotes are
not available, we utilize other valuation techniques or models to estimate
market values. These modeling techniques require us to make estimations of
future prices, price correlation and market volatility and liquidity. Our actual
results may differ from our estimates, and these differences can be positive or
negative.
During the second half of 2002, the Company entered into various cash flow
hedging swap contracts to fix cash flows relating to a portion of the Company's
oil and gas production. All of these qualified for hedge accounting and none
extended beyond a year and a half. The aggregate fair market value of the swaps
was a liability of $4.1 million as of December 31, 2002. The Company recorded
$2.6 million of loss, net of taxes, in other comprehensive loss within
shareholders' equity as these hedges were highly effective.
NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") released
SFAS No. 143, Accounting for Asset Retirement Obligations, which is required to
be adopted no later than January 1, 2003. SFAS 143 addresses the financial
accounting and reporting obligations and retirement costs related to the
retirement of tangible long-lived assets. Among other things, SFAS 143 will
require oil and gas companies to reflect decommissioning liabilities on the face
of the balance sheet at fair value on a discounted basis. Historically, ERT has
reflected this liability on the balance sheet on an undiscounted basis. The
Company will adopt this standard, as required, effective January 1, 2003.
Management currently believes adoption of this standard will result in
additional diluted earnings per share in the first quarter of 2003 of between
$0.01 and $.03 and adjustments to certain balance sheet accounts including a
decrease in Decommissioning Liabilities of approximately $30 million due to
discounting.
In November 2002, FASB interpretation ("FIN") No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others ("FIN No. 45") was issued. FIN No. 45
requires a guarantor to recognize at the inception of a guarantee a liability
for the fair value of the obligation undertaken in issuing the guarantee. FIN
No. 45 also expands the disclosures required to be made by a guarantor about its
obligations under certain guarantees that it has issued. Initial recognition and
measurement provisions of FIN No. 45 are applicable on a prospective basis to
guarantees issued or
29
modified. The disclosure requirements are effective immediately. The Company
does not expect FIN No. 45 to have a material effect on its consolidated
financial statements.
In January 2003, FIN No. 46, Consolidation of Variable Interest Entities
was issued which requires that companies that control another entity through
interests other than voting interests should consolidate the controlled entity.
FIN No. 46 applies immediately to variable interest entities created after
January 31, 2003, and applies in the first interim period beginning after June
15, 2003 to variable interest entities created before February 1, 2003. The
related disclosure requirements are effective immediately. The Company does not
believe that the adoption of this interpretation will have a material impact on
its consolidated financial statements.
RESULTS OF OPERATIONS
COMPARISON OF YEARS ENDED 2002 AND 2001
Revenues. During the year ended December 31, 2002, the Company's revenues
increased $75.6 million, or 33%, to $302.7 million compared to $227.1 million
for the year ended December 31, 2001 with the Subsea and Salvage segment
contributing all of the increase. Subsea and Salvage revenues increased to
$239.9 million for the year ended December 31, 2002 as compared to $163.7
million in the prior year. Our acquisitions of Canyon Offshore and Well Ops UK
Ltd added $37.5 million and $21.4 million, respectively. The remainder of the
increase is due to the addition of three deepwater construction vessels: the
Q4000, the Intrepid and the Eclipse.
Oil and Gas Production revenue for the year ended December 31, 2002
decreased less than 1% to $62.8 million from $63.4 million during the prior
year. An increase in production, lead by the significant Shell and Hess
acquisitions made late in the third quarter of 2002, was offset by lower average
realized commodity prices. Oil and gas production increased 19% to 16.6 Bcfe in
2002 from 13.9 Bcfe during 2001, while our average realized commodity price
declined 15% to $3.71 per Mcfe ($3.39 per Mcf of natural gas and $25.54 per
barrel of oil) in 2002 as compared to $4.37 per Mcfe ($4.44 per Mcf of natural
gas and $24.54 per barrel of oil) in the prior year. Oil and condensate
represented 38% of ERT revenue in 2002 compared to 30% in 2001.
Gross Profit. Gross profit of $53.8 million for the year ended December
31, 2002 was $13.1 million, or 20%, below the $66.9 million gross profit
recorded in the prior year with both segments contributing to the decline.
Subsea and Salvage gross profit decreased $9.6 million, or 26%, to $27.0 million
during the year ended December 31, 2002 compared to $36.7 million during 2001.
Our DP vessels generated $8.6 million of gross profit, only 43% of the $20.1
million generated in the prior year, due in part to the charges recorded in the
fourth quarter related to a contract dispute. Margins for this segment decreased
to 11% for the year ended December 31, 2002 compared to 22% in 2001. While
Aquatica margins held strong at 30% due to a large amount of shelf repair work
following Hurricane Lili, the DP fleet only contributed 7% margins in 2002
compared to 25% in the prior year.
Oil and Gas Production gross profit decreased $3.5 million from $30.2
million in the year ended December 31, 2001 to $26.7 million for the year ended
December 31, 2002 due mainly to the aforementioned decrease in average realized
commodity prices. Margins declined to 43% during 2002 from 48% during 2001 due
to platform repairs and the time necessary for pipelines to return to full
production following Hurricane Lili.
Selling and Administrative Expenses. Selling and administrative expenses
of $32.8 million in 2002 were $11.5 million, or 54%, higher than the $21.3
million incurred during 2001. The increase is primarily due to the acquisitions
of Canyon and Well Ops UK Ltd. and a charge taken for the settlement of
litigation in the fourth quarter of 2002.
Net Interest (Income) Expense and Other. The Company reported net interest
expense and other of $2.0 million for the year ended December 31, 2002 in
contrast to $1.3 million for the prior year. This increase is due to the
increase in debt from our capital program, which resulted in an additional $2.2
million in interest expense, offset by a $1.1 million gain on our foreign
currency hedge related to the Well Ops (U.K.) Limited acquisition included in
other income in the third quarter of 2002.
30
Income Taxes. Income taxes decreased to $6.7 million for the year ended
December 31, 2002, compared to $15.5 million in the prior year due to decreased
profitability. Federal income taxes were provided at the statutory rate of 35%
in 2002. However, our deduction of Q4000 construction costs as Research and
Development expenditures for federal tax purposes resulted in CDI paying no
federal income taxes in 2002 and 2001. Since the deduction of Q4000 construction
costs affects financial and taxable income in different years, the entire 2002
and 2001 provisions for federal taxes were reflected as deferred income taxes.
Net Income. Net income of $12.4 million for the year ended December 31,
2002 was $16.6 million, or 57%, less than the $28.9 million earned in 2001 as a
result of factors described above.
COMPARISON OF YEAR ENDED DECEMBER 31, 2001 AND 2000
Revenues. During the year ended December 31, 2001, the Company's revenues
increased 25% to $227.1 million compared to $181.0 million for the year ended
December 31, 2000 with the Subsea and Salvage segment contributing all of the
increase. Aquatica revenues increased 80% to $37.0 million for 2001 from $20.6
million in the prior year due, in part, to added capacity as a result of our
acquisition of Professional Divers of New Orleans, Inc. in February 2001 and
improved OCS activity. Revenues generated from our DP fleet increased 54% to
$79.3 million during 2001 compared to $51.4 million in 2000 due mainly to vessel
utilization improving from 56% during 2000 to 87%. This increased utility
reflects improved CDI market share, an expansion in the scope of Deepwater
services provided and expansion into other regions (Mexico and Trinidad).
Oil and Gas Production revenue for the year ended December 31, 2001
decreased 10% to $63.4 million from $70.8 million during the prior year due to a
10% decrease in production from 15.5 Bcfe in 2000 compared to 13.9 Bcfe during
2001. ERT received an average of $4.44 per Mcf for natural gas and $24.54 per
Bbl for oil during 2001 compared to $4.04 per Mcf and $28.91 per Bbl in 2000.
Oil and condensate represented 30% of ERT's revenues in 2001 versus 27% in 2000.
Gross Profit. Gross profit of $66.9 million for the year ended December
31, 2001 was 21% greater than the $55.4 million gross profit recorded in the
prior year with Subsea and Salvage contracting gross profit providing all of the
increase and offsetting a $9.1 million decline in oil and gas production gross
profit. Subsea and Salvage margins improved from 15% for the year ended December
31, 2000 to 22% during the year ended December 31, 2001 due mainly to the
increase in utilization due to increased marine construction activity, even
though we earned only 5% margins on $15 million of Nansen/Boomvang volume that
was mostly pass-through revenue.
Oil and Gas Production gross profit decreased $9.1 million from $39.3
million in the year ended December 31, 2000 to $30.2 million for the year ended
December 31, 2001 due mainly to the aforementioned 10% decline in production,
higher amortization rates in 2001 than 2000 and a $1.0 million charge for
accounts receivable exposure related to the Enron bankruptcy.
Selling and Administrative Expenses. Selling and administrative expenses
were $21.3 million in 2001, which is relatively flat (3% increase) with the
$20.8 million incurred during 2000. Given the increased revenues, this tight
cost control provided a two point margin improvement (i.e., 9% margin for the
year ended December 31, 2001 as compared to 11% for the year ended December 31,
2000).
Net Interest (Income) Expense and Other. The Company reported net interest
expense and other of $1.3 million for the year ended December 31, 2001 in
contrast to $554,000 for the prior year as average cash balances (net of MARAD
financing) declined during 2001 as compared to 2000 due mainly to costs
associated with construction of the Q4000 and the Intrepid conversion.
Income Taxes. Income taxes increased to $15.5 million for the year ended
December 31, 2001, compared to $11.6 million in the prior year due to increased
profitability. Federal income taxes were provided at the statutory rate of 35%
in 2001. However, our deduction of Q4000 construction costs as Research and
Development expenditures for federal tax purposes resulted in CDI paying no
federal income taxes in 2001 and 2000. Since the deduction of Q4000 construction
costs affects financial and taxable income in different years, the entire 2001
and 2000 provisions for federal taxes were reflected as deferred income taxes.
In
31
addition, the balance sheet includes a $10.0 million income tax receivable as of
December 31, 2000 which reflects our amending prior year tax returns to reflect
the deduction of such costs (these tax refunds were received in January 2001).
Net Income. Net income of $28.9 million for the year ended December 31,
2001 was $5.6 million, or 24%, more than 2000 as a result of factors described
above.
LIQUIDITY AND CAPITAL RESOURCES
During the three years following our initial public offering in 1997,
internally generated cash flow funded approximately $164 million of capital
expenditures and enabled us to remain essentially debt-free. In August 2000, we
closed the long-term MARAD financing for construction of the Q4000. This U.S.
Government guaranteed financing is pursuant to Title XI of the Merchant Marine
Act of 1936 which is administered by the Maritime Administration. We refer to
this debt as MARAD Debt. In January 2002, the Maritime Administration agreed to
expand the facility to $160 million to include the modifications to the vessel
which had been approved during 2001. Through December 31, 2002, we have drawn
$143.5 million on this facility. In January 2002, we acquired Canyon Offshore,
Inc., in July 2002 we acquired the Well Operations Business Unit of
Technip-Coflexip and in August 2002, ERT made two significant property
acquisitions (see further discussion below). These acquisitions have
significantly increased our debt to total book capitalization ratio from 31% at
December 31, 2001 to 40% at December 31, 2002. Additionally, increased
operations coupled with depressed market conditions have caused our working
capital to decrease from $48.6 million at December 31, 2001 to $4.4 million at
December 31, 2002. In order to reduce this leverage, on January 8, 2003, CDI
completed the private placement of $25 million of a newly designated class of
cumulated convertible preferred stock (Series A-1 Cumulative Convertible
Preferred Stock, par value $0.01 per share) which is convertible into 833,334
shares of Cal Dive common stock at $30 per share.
Operating Activities. Net cash provided by operating activities was $65.2
million during the year ended December 31, 2002, as compared to $89.1 million
during 2001. This decrease was due mainly to decreased profitability and to last
year's collection of a $10 million tax refund from the Internal Revenue Service
relating to the deduction of Q4000 construction costs as research and
development expenditures for federal tax purposes. Depreciation and amortization
also increased $10.2 million to $44.8 million due to the depreciation of new
vessels placed in service during 2002 and to increased depletion related to
increased production levels from ERT. This was offset by an increase in funding
required for accounts receivable collections during 2002 compared to 2001.
Net cash provided by operating activities was $89.1 million during the year
ended December 31, 2001, as compared to $53.7 million during 2000. This increase
was due mainly to increased profitability and collection of the $10 million tax
refund from the Internal Revenue Service noted above. Timing of accounts payable
payments provided $22.3 million of the increase due mainly to expenses accrued
at December 31, 2001 on the Nansen/Boomvang project which carries a large
component of pass-through costs. This project also accounted for the significant
increase in unbilled revenue at December 31, 2001 ($10.7 million versus $1.9
million at December 31, 2000), as the next scheduled invoicing milestone was
achieved in January 2002. This was offset by a $20.3 million decrease in funding
from accounts receivable collections during 2001 compared to 2000 as we have
extended payment terms to Horizon Offshore. In addition, depreciation and
amortization increased $3.8 million to $34.5 million for 2001 due mainly to the
depreciation of newly acquired vessels in service.
Investing Activities. Capital expenditures have consisted principally of
strategic asset acquisitions related to the purchase of DP vessels, the Eclipse
and Mystic Viking; construction of the Q4000 and conversion of the Intrepid;
acquisition of Aquatica, Professional Divers, Canyon Offshore, Inc. and Well Ops
(U.K.) Limited; improvements to existing vessels and the acquisition of oil and
gas properties. As a result of our anticipation of an acceleration in Deepwater
demand over the next several years, we incurred $316.4 million of capital
expenditures (including the acquisitions of Canyon and Well Ops (U.K.) Limited
and investments in
32
the two Deepwater developments, Gunnison and Deepwater Gateway L.L.C.) during
2002, $151.3 million during 2001 and $95.1 million in 2000.
We incurred $161.8 million of capital expenditures during the year ended
December 31, 2002, compared to $151.3 million during the prior year. Included in
the capital expenditures in 2002 is $29.1 million for the construction of the
Q4000 and $20.8 million relating to the Intrepid DP conversion and Eclipse
upgrade. Also included is over $25 million in ERT offshore property acquisitions
(see discussion below) as well as approximately $53 million related to Gunnison
development costs, including the spar. Included in the $151.3 million of capital
expenditures in 2001 is $53 million for the construction of the Q4000, $33
million for the conversion of the Intrepid, $40 million relating to the purchase
of two DP vessels (the 240-foot by 52-foot Mystic Viking and the 370-foot by
67-foot Eclipse), and production partnering expenditures of $20 million for
initial Gunnison development costs and the ERT 2001 Well Enhancement Program. In
addition, in March 2001, CDI acquired substantially all of the assets of
Professional Divers of New Orleans in exchange for $11.5 million. The assets
purchased included the 165-foot four-point moored DSV the Mr. Sonny, three
utility vessels and associated diving equipment including two saturation diving
systems. This acquisition was accounted for as a purchase with the acquisition
price of $11.5 million being allocated to the assets acquired and liabilities
assumed based upon their estimated fair values with the balance of the purchase
price ($2.8 million) being recorded as goodwill.
On August 30, 2002, ERT acquired the 74.8% working interest of Shell
Exploration & Production Company in the South Marsh Island 130 (SMI 130) field.
ERT paid $10.3 million in cash and assumed Shell's pro-rata share of the related
decommissioning liability. ERT also completed the purchase of interests in seven
Gulf of Mexico fields from Amerada Hess including its 25% ownership position in
SMI 130 for $9.3 million in cash and assumption of Amerada Hess' pro-rata share
of the related decommissioning liability. As a result, ERT is the operator with
an effective 100% working interest in that field.
In July 2002, CDI purchased the Subsea Well Operations Business Unit of CSO
Ltd., a wholly owned subsidiary of Technip-Coflexip, for approximately $72.0
million ($68.6 million cash and $3.4 million deferred tax liability assumption).
Well Ops (U.K.) Limited performs life of field well operations and marine
construction tasks primarily in the North Sea. The assets purchased include the
Seawell, a 368-foot DPDSV capable of supporting manned diving, ROVs and well
operations. The acquisition was accounted for as a business purchase with the
acquisition price allocated to the assets acquired and liabilities assumed based
upon their estimated fair values, with the excess being recorded as goodwill.
During the fourth quarter of 2002 the Company completed its purchase price
allocation, including obtaining an appraisal of the Seawell, resulting in $50
million allocated to this vessel, $1.5 million allocated to patented technology
(to be amortized over 20 years) and goodwill of approximately $20.6 million as
of December 31, 2002. The results of Well Ops (U.K.) Limited are included in the
accompanying statements of operations since the date of the purchase, July 1,
2002.
In January 2002, CDI purchased Canyon, a supplier of remotely operated
vehicles (ROVs) and robotics to the offshore construction and telecommunications
industries. CDI purchased Canyon for cash of $52.8 million, the assumption of
$9.0 million of Canyon debt (offset by $3.1 million of cash acquired), 181,000
shares of our common stock (143,000 shares of which we purchased as treasury
shares during the fourth quarter of 2001) and a commitment to purchase the
redeemable stock in Canyon at a price to be determined by Canyon's performance
during the years 2002 through 2004 from continuing employees at a minimum
purchase price of $13.53 per share. As they are employees, amounts paid, if any,
in excess of the $13.53 per share will be recorded as compensation expense. No
such expense was recorded in 2002. These remaining shares have been classified
as redeemable stock in subsidiary in the accompanying balance sheet and will be
adjusted to their estimated redemption value at each reporting period based on
Canyon's performance. The acquisition was accounted for as a purchase with the
acquisition price allocated to the assets acquired and liabilities assumed based
upon their estimated fair values, with the excess being recorded as goodwill.
The allocation of the $70.5 million purchase price was as follows: ROVs and
equipment ($22.9 million); net working capital assumed ($4.0 million) and
goodwill ($43.6 million). The results of Canyon are included in the accompanying
statements of operations since the date of the purchase, January 2, 2002.
33
In April 2002, ERT acquired a 100% interest in East Cameron Block 374,
including existing wells, equipment and improvements. The property, located in
425 feet of water, was jointly owned by Murphy Exploration & Production Company
and Callon Petroleum Operating Company. Terms included a cash payment of
approximately $3 million to reimburse the owners for the inception-to-date cost
of the subsea wellhead and umbilical and an overriding royalty interest in
future production. Cal Dive completed the temporarily abandoned number one well
and performed a subsea tie-back to host platform. The cost of completion and
tie-back was approximately $7 million with first production occurring in August
2002.
In June 2002, ERT acquired a package of offshore properties from Williams
Exploration and Production. ERT paid $4.9 million and assumed the pro-rata share
of the abandonment obligation for the acquired interests. The blocks purchased
represent an average 30% net working interest in 26 Gulf of Mexico leases.
In early 2002, CDI, along with El Paso Energy Partners, formed Deepwater
Gateway L.L.C. (a 50/50 venture) to design, construct, install, own and operate
a tension leg platform ("TLP") production hub primarily for Anadarko Petroleum
Corporation's Marco Polo field discovery in the Deepwater Gulf of Mexico. Our
share of the construction costs is estimated to be approximately $110 million
(approximately $43 million of which had been incurred as of December 31, 2002).
In August 2002, the Company along with El Paso, completed a non-recourse project
financing for this venture, terms of which include a minimum equity investment
for CDI of $33 million, all of which had been paid as of December 31, 2002 and
is recorded as Investment in Deepwater Gateway L.L.C. in the accompanying
consolidated balance sheet. Terms of the financing also require CDI to guarantee
a balloon payment at the end of the financing term in 2008 (estimated to be
$22.5 million). The Company has not recorded any liability for this guarantee as
management does not believe performance is likely to occur.
In April 2000, ERT acquired a 20% working interest in Gunnison, a Deepwater
Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corporation. Consistent with
CDI's philosophy of avoiding exploratory risk, financing for the exploratory
costs of approximately $20 million was provided by an investment partnership
(OKCD Investments, Ltd.), the investors of which are CDI senior management, in
exchange for an overriding royalty interest of 25% of CDI's 20% working
interest. CDI provided no guarantees to the investment partnership. The Board of
Directors established three criteria to determine a commercial discovery and the
commitment of Cal Dive funds: 75 million barrels (gross) of reserves, total
development costs of $500 million consistent with 75 MBOE, and a CDI estimated
shareholder return of no less than 12%. Kerr-McGee, the operator, drilled
several exploration wells and sidetracks in 3,200 feet of water at Garden Banks
667, 668 and 669 (the Gunnison prospect) and encountered significant potential
reserves resulting in the three criteria being achieved during 2001. With the
sanctioning of a commercial discovery, the Company is funding ongoing
development and production costs. Cal Dive's share of such project development
costs is estimated in a range of $100 million to $110 million ($63.3 million of
which had been incurred by December 31, 2002) with over half of that for
construction of the spar. See footnote 10 to the Company's Consolidated
Financial Statements included herein for discussion of financing relating to the
spar construction.
Financing Activities. We have financed seasonal operating requirements and
capital expenditures with internally generated funds, borrowings under credit
facilities, the sale of common stock and project financings. In August 2000, we
closed a $138.5 million long-term financing for construction of the Q4000. In
January 2002, the Maritime Administration agreed to expand the facility to $160
million to include the modifications to the vessel which had been approved
during 2001. During 2001 and 2002, we borrowed $59.5 million and $43.9 million,
respectively, on this facility bringing the total to $142.1 million at December
31, 2002. The MARAD debt is payable in equal semi-annual installments beginning
in August 2002 and maturing 25 years from such date. It is collateralized by the
Q4000, with Cal Dive guaranteeing 50% of the debt, and bears an interest rate
which currently floats at a rate approximating AAA Commercial Paper yields plus
20 basis points (approximately 2% as of December 31, 2002). For a period up to
ten years from delivery of the vessel in April 2002, the Company has options to
lock in a fixed rate. In accordance with the MARAD debt agreements, we are
required to comply with certain covenants and restrictions, including the
maintenance of minimum net worth, working capital and debt-to-equity
requirements. As of December 31, 2002, we were in compliance with these
covenants.
34
The Company has a revolving credit facility which was increased from $40
million to $70 million during 2002 and the term extended for three years. This
facility is collateralized by accounts receivable and most of the remaining
vessel fleet, bears interest at LIBOR plus 125-250 basis points depending on CDI
leverage ratios (approximately 4.2% as of December 31, 2002) and, among other
restrictions, includes three financial covenants (cash flow leverage, minimum
interest coverage and fixed charge coverage). As of December 31, 2002, the
Company had drawn $52.6 million under this revolving credit facility and was in
compliance with these covenants with the exception of the cash flow leverage
covenant, for which the Company obtained a waiver.
In November 2001, ERT entered into a five-year lease transaction with an
entity owned by a third party to fund CDI's portion of the construction costs
($67 million) of the spar for the Gunnison field. As of December 31, 2001 and
June 30, 2002, the entity had drawn down $5.6 million and $22.8 million,
respectively, on this facility. Accrued interest cost on the outstanding balance
is capitalized to the cost of the facility during construction and is payable
monthly thereafter. In August 2002, CDI acquired 100% of the equity of the
entity and converted the notes into a term loan ("Gunnison Term Loan"). The
total commitment of the loan was reduced to $35 million and will be payable in
quarterly installments of $1.75 million for three years after delivery of the
spar with the remaining $15.75 million due at the end of the three years. The
facility bears interest at LIBOR plus 225-300 basis points depending on CDI
leverage ratios (approximately 4.4% as of December 31, 2002) and includes, among
other restrictions, three financial covenants (cash flow leverage, minimum
interest coverage and debt to total book capitalization). The Company was in
compliance with these covenants as of December 31, 2002 with the exception of
the cash flow leverage covenant, for which the Company obtained a waiver. The
debt ($29.3 million at December 31, 2002) and related asset have been reflected
on CDI's balance sheet beginning in the third quarter of 2002. The purchase
price was allocated entirely to construction in progress.
In May 2002, CDI sold 3.4 million shares of primary common stock for $23.16
per share, along with 517,000 additional shares to cover over-allotments. Net
proceeds to the Company of approximately $87.2 million were used for the
Coflexip Well Operation acquisition, ERT acquisitions and to retire debt under
the Company's revolving line of credit.
During 2002, we made payments of $5.2 million on capital leases assumed in
the Canyon acquisition. The only other financing activity during 2002, 2001 and
2000 involved the exercise of employee stock options.
In January 2003, CDI completed the private placement of $25 million of
preferred stock which is convertible into 833,334 shares of CDI common stock at
$30 per share. The preferred stock was issued to a private investment firm. The
preferred stock holder has the right to purchase as much as $30 million in
additional preferred stock for a period of two years beginning in July, 2003.
The conversion price of the additional preferred stock will equal 125% of the
then prevailing price of Cal Dive common stock, subject to a minimum conversion
price of $30 per common share. After the second anniversary, the holder may
redeem the value of its original investments in the preferred shares to be
settled in common stock or cash at the discretion of the Company. Under certain
conditions, the holder could redeem its investment prior to the second
anniversary. Prior to the conversion, shares will be included in the Company's
fully diluted earnings per share under the if converted method based on the
Company's average common share price during the applicable period. Subsequent to
year-end the Company filed a registration statement registering approximately
7.5 million shares of common stock relating to this transaction, the maximum
potential total number of shares of common stock redeemable under certain
circumstances, subject to the Company's ability to redeem with cash, under the
terms of the agreement.
35
The following table summarizes our contractual cash obligations as of
December 31, 2002 and the scheduled years in which the obligation are
contractually due:
LESS THAN
(IN THOUSANDS) TOTAL 1 YEAR 2-3 YEARS 4-5 YEARS THEREAFTER
-------------- -------- --------- --------- --------- ----------
MARAD debt......................... $142,128 $ 2,766 $ 6,093 $ 6,925 $126,344
Gunnison term debt................. 29,270 -- 14,000 15,270 --
Revolving debt..................... 52,591 -- 52,591 -- --
Gunnison development............... 46,700 41,000 5,700 -- --
Investments in Deepwater Gateway
L.L.C.(A)........................ -- -- -- -- --
Operating Leases................... 19,018 8,848 9,231 552 387
Redeemable stock in subsidiary..... 7,528 2,509 5,019 -- --
Canyon capital leases and other.... 3,788 1,435 1,967 386 --
-------- ------- ------- ------- --------
Total Cash Obligation.............. $301,023 $56,558 $94,601 $23,133 $126,731
======== ======= ======= ======= ========
---------------
(A) Excludes CDI guarantee of balloon payment due in 2008 on non-recourse
project financing (estimated to be $22.5 million).
In addition, in connection with our business strategy, we evaluate
acquisition opportunities (including additional vessels as well as interest in
offshore natural gas and oil properties). We believe that internally-generated
cash flow, borrowings under existing credit facilities and use of project
financings along with other debt and equity alternatives will provide the
necessary capital to meet these obligations and achieve our planned growth.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company is currently exposed to market risk in two major areas:
commodity prices and foreign currency. Because all of the Company's debt at
December 31, 2002 was based on floating rates, changes in interest would,
assuming all other things equal, have a minimal impact on the fair market value
of the debt instruments. Assuming December 31, 2002 debt levels, every 100 basis
points move in interest rates would result in $2.3 million of annualized
interest expense or savings, as the case may be, to the Company.
COMMODITY PRICE RISK
The Company has utilized derivative financial instruments with respect to a
portion of 2002 and 2003 oil and gas production to achieve a more predictable
cash flow by reducing its exposure to price fluctuations. The Company does not
enter into derivative or other financial instruments for trading purposes.
As of December 31, 2002, the Company has the following volumes under
derivative contracts related to its oil and gas producing activities:
INSTRUMENT AVERAGE MONTHLY WEIGHTED
PRODUCTION PERIOD TYPE VOLUMES AVERAGE PRICE
----------------- ---------- --------------- -------------
Crude Oil:
January -- December 2003................ Swap 46 MBbl $26.50
January -- December 2003................ Swap 30 MBbl $26.82
Natural Gas:
January -- March 2003................... Swap 800,000 MMBtu $ 4.21
April -- December 2003.................. Swap 400,000 MMBtu $ 4.02
April -- December 2003.................. Swap 200,000 MMBtu $ 4.21
Changes in NYMEX oil and gas strip prices would, assuming all other things
being equal, cause the fair market value of these instruments to increase or
decrease.
36
Subsequent to December 31, 2002, the Company entered into natural gas swaps
for the period April through December 2003. The contracts cover 200,000 MMBtu
per month at $4.97.
FOREIGN CURRENCY EXCHANGE RATES
Because we operate in various oil and gas exploration and production
regions in the world, we conduct a portion of our business in currencies other
than the U.S. dollar (primarily with respect to Well Ops (U.K.) Limited). The
functional currency for Well Ops (U.K.) Limited is the applicable local
currency. Although the revenues are denominated in the local currency, the
effects of foreign currency fluctuations are partly mitigated because local
expenses of such foreign operations also generally are denominated in the same
currency. The impact of exchange rate fluctuations during the twelve months
ended December 31, 2002 did not have a material effect on reported amounts of
revenues or net income.
Assets and liabilities of Well Ops (U.K.) Limited are translated using the
exchange rates in effect at the balance sheet date, resulting in translation
adjustments that are reflected in accumulated other comprehensive loss in the
stockholders' equity section of our balance sheet. Approximately 12% of our net
assets are impacted by changes in foreign currencies in relation to the U.S.
dollar. We recorded a $2.5 million adjustment, net of taxes, to our equity
account for the twelve months ended December 31, 2002 to reflect the net impact
of the decline of the British Pound against the U.S. dollar.
Canyon Offshore, the Company's ROV subsidiary, has operations in the United
Kingdom and Southeast Asia sectors. Canyon conducts the majority of its affairs
in these regions in U.S. dollars which it considers the functional currency.
When currencies other than the U.S. dollar are to be paid or received the
resulting gain or loss from translation is recognized in the statements of
operations. These amounts for the year ended December 31, 2002 were not material
to the Company's results of operations or cash flows.
37
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Report of Independent Auditors.............................. 39
Report of Independent Public Accountants.................... 40
Consolidated Balance Sheets -- December 31, 2002 and 2001... 41
Consolidated Statements of Operations for the years ended
December 31, 2002, 2001 and 2000.......................... 42
Consolidated Statements of Shareholders' Equity for the
years ended December 31, 2002, 2001 and 2000.............. 43
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000.......................... 44
Notes to Consolidated Financial Statements.................. 45
38
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholders of
Cal Dive International, Inc.:
We have audited the accompanying consolidated balance sheet of Cal Dive
International, Inc. and Subsidiaries as of December 31, 2002 and the related
consolidated statements of operations, shareholders' equity and cash flows for
the year then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit. The consolidated financial statements
of Cal Dive International, Inc. as of December 31, 2001 and for each of the
years in the two year period ended December 31, 2001 were audited by other
auditors who have ceased operations. Those auditors expressed an unqualified
opinion on those consolidated financial statements in their report dated
February 18, 2002 before the reclassification adjustments and conforming
disclosures described in Note 10.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Cal Dive
International, Inc. and Subsidiaries at December 31, 2002 and the consolidated
results of their operations and their cash flows for the year then ended in
conformity with accounting principles generally accepted in the United States.
As discussed in Note 1 to the accompanying consolidated financial
statements, the Company adopted Statement of Financial Accounting Standards No.
142, "Goodwill and Other Intangible Assets" in 2002.
As described above, the consolidated financial statements of Cal Dive
International, Inc. and Subsidiaries as of December 31, 2001 and 2000, and for
the years then ended were audited by other auditors who have ceased operations.
As described in Note 10, the consolidated financial statements as of and for the
year ended December 31, 2001 have been revised. We audited the reclassification
adjustments and conforming disclosures described in Note 10 applied to revise
the 2001 financial statements. In our opinion, such reclassification adjustments
and conforming disclosures are appropriate and have been properly applied.
However, we were not engaged to audit, review or apply any procedures to the
2001 consolidated financial statements of the Company other than with respect to
such reclassification adjustments and conforming disclosures and, accordingly,
we do not express an opinion or any other form of assurance on the 2001
consolidated financial statements taken as a whole.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 17, 2003
39
NOTE: THE REPORT OF ARTHUR ANDERSEN LLP PRESENTED BELOW IS A COPY OF A
PREVIOUSLY ISSUED ARTHUR ANDERSEN LLP REPORT AND SAID REPORT HAS NOT BEEN
REISSUED BY ARTHUR ANDERSEN LLP NOR HAS ARTHUR ANDERSEN LLP PROVIDED A CONSENT
TO THE INCLUSION OF ITS REPORT IN THIS FORM 10-K.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of
Cal Dive International, Inc.:
We have audited the accompanying consolidated balance sheets of Cal Dive
International Inc. (a Minnesota corporation) and subsidiaries as of December 31,
2001 and 2000, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Cal Dive International,
Inc., and subsidiaries as of December 31, 2001 and 2000, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 18, 2002
40
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
(IN THOUSANDS)
DECEMBER 31,
--------------------
2002 2001
--------- --------
ASSETS
Current assets:
Cash and cash equivalents................................. $ -- $ 37,123
Restricted cash........................................... 2,506 --
Accounts receivable --
Trade, net of revenue allowance on gross amounts billed
of $7,156 and $4,262.................................. 52,808 45,527
Unbilled revenue........................................ 22,610 10,659
Other current assets...................................... 28,266 20,055
--------- --------
Total current assets............................... 106,190 113,364
--------- --------
Property and equipment...................................... 726,878 423,742
Less -- Accumulated depreciation.......................... (130,527) (92,430)
--------- --------
596,351 331,312
Other assets:
Goodwill, net............................................. 79,758 14,973
Investment in Deepwater Gateway, L.L.C. .................. 32,688 --
Other assets, net......................................... 52,045 34,647
--------- --------
$ 867,032 $494,296
========= ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 62,798 $ 42,252
Accrued liabilities....................................... 34,790 21,011
Income taxes payable...................................... -- --
Current maturities of long-term debt...................... 4,201 1,500
--------- --------
Total current liabilities.......................... 101,789 64,763
--------- --------
Long-term debt.............................................. 223,576 98,048
Deferred income taxes....................................... 102,230 75,805
Decommissioning liabilities................................. 92,420 29,331
Other long term liabilities................................. 1,972 --
--------- --------
Total liabilities.................................. 521,987 267,947
Redeemable stock in subsidiary.............................. 7,528 --
Commitments and contingencies
Shareholders' equity:
Common stock, no par, 120,000 shares authorized, 51,060
and 46,239 shares issued................................ 195,405 99,105
Retained earnings......................................... 145,947 133,570
Treasury stock, 13,602 and 13,783 shares, at cost......... (3,741) (6,326)
Accumulated other comprehensive loss...................... (94) --
--------- --------
Total shareholders' equity......................... 337,517 226,349
--------- --------
$ 867,032 $494,296
========= ========
The accompanying notes are an integral part of these consolidated financial
statements.
41
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
------------------------------
2002 2001 2000
-------- -------- --------
Net revenues:
Subsea and salvage........................................ $239,916 $163,740 $110,217
Oil and gas production.................................... 62,789 63,401 70,797
-------- -------- --------
302,705 227,141 181,014
Cost of sales:
Subsea and salvage........................................ 212,868 127,047 94,104
Oil and gas production.................................... 36,045 33,183 31,541
-------- -------- --------
Gross profit........................................... 53,792 66,911 55,369
Selling and administrative expenses......................... 32,783 21,325 20,800
-------- -------- --------
Income from operations...................................... 21,009 45,586 34,569
Net interest expense and other............................ 1,968 1,290 554
-------- -------- --------
Income before income taxes.................................. 19,041 44,296 34,015
Provision for income taxes................................ 6,664 15,504 11,555
Minority Interest......................................... -- (140) (866)
-------- -------- --------
Net income........................................... $ 12,377 $ 28,932 $ 23,326
======== ======== ========
Net income per share:
Basic..................................................... $ 0.35 $ 0.89 $ 0.74
Diluted................................................... 0.35 0.88 0.72
======== ======== ========
Weighted average common shares outstanding:
Basic..................................................... 35,504 32,449 31,588
Diluted................................................... 35,749 33,055 32,341
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
42
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)
ACCUMULATED
COMMON STOCK TREASURY STOCK OTHER TOTAL
----------------- RETAINED ----------------- COMPREHENSIVE SHAREHOLDERS'
SHARES AMOUNT EARNINGS SHARES AMOUNT LOSS EQUITY
------ -------- -------- ------- ------- ------------- -------------
Balance, December 31, 1999.... 44,790 $ 73,311 $ 81,312 (13,640) $(3,751) $ -- $150,872
Net income.................... -- -- 23,326 -- -- -- 23,326
Activity in company stock
plans, net.................. 485 5,740 -- -- -- -- 5,740
Sale of common stock, net..... 610 14,787 -- -- -- -- 14,787
------ -------- -------- ------- ------- ------- --------
Balance, December 31, 2000.... 45,885 93,838 104,638 (13,640) (3,751) -- 194,725
Net income.................... -- -- 28,932 -- -- -- 28,932
Activity in company stock
plans, net.................. 354 5,267 -- -- -- -- 5,267
Purchase of treasury shares... -- -- -- (143) (2,575) -- (2,575)
------ -------- -------- ------- ------- ------- --------
Balance, December 31, 2001.... 46,239 99,105 133,570 (13,783) (6,326) -- 226,349
Comprehensive income
Net income.................. -- -- 12,377 -- -- -- 12,377
Foreign currency translation
adjustments............... -- -- -- -- -- 2,548 2,548
Unrealized loss on commodity
hedges.................... -- -- -- -- -- (2,642) (2,642)
--------
Comprehensive income.......... 12,283
--------
Sale of common stock, net..... 3,961 87,219 -- -- -- -- 87,219
Activity in company stock
plans, net.................. 860 7,376 -- -- -- -- 7,376
Issuance of shares in business
acquisition................. -- 1,705 -- 181 2,585 -- 4,290
------ -------- -------- ------- ------- ------- --------
Balance, December 31, 2002.... 51,060 $195,405 $145,947 (13,602) $(3,741) $ (94) $337,517
====== ======== ======== ======= ======= ======= ========
The accompanying notes are an integral part of these consolidated financial
statements.
43
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
--------------------------------
2002 2001 2000
--------- --------- --------
Cash flows from operating activities:
Net income............................................... $ 12,377 $ 28,932 $ 23,326
Adjustments to reconcile net income to net cash provided
by operating activities --
Depreciation and amortization......................... 44,755 34,533 30,730
Deferred income taxes................................. 6,130 15,504 21,085
Gain on sale of assets................................ (10) (1,881) (3,292)
Changes in operating assets and liabilities:
Accounts receivable, net............................ (1,728) (13,594) 6,723
Other current assets................................ (7,086) 2,760 (4,298)
Accounts payable and accrued liabilities............ 14,730 21,263 (1,030)
Income taxes receivable/payable..................... 1,476 10,014 (7,256)
Other noncurrent, net............................... (5,443) (8,424) (12,287)
--------- --------- --------
Net cash provided by operating activities........ 65,201 89,107 53,701
--------- --------- --------
Cash flows from investing activities:
Capital expenditures..................................... (161,766) (151,261) (95,124)
Acquisition of businesses, net of cash acquired.......... (118,331) (11,500) --
Investment in Deepwater Gateway, L.L.C. ................. (32,688) -- --
Restricted cash.......................................... (2,506) 2,624 6,062
Prepayments and deposits related to salvage operations... -- 782 826
Proceeds from sales of property.......................... 483 1,530 3,124
Insurance proceeds from loss of vessel................... -- -- 7,118
--------- --------- --------
Net cash used in investing activities............ (314,808) (157,825) (77,994)
--------- --------- --------
Cash flows from financing activities:
Sale of common stock, net of transaction costs........... 87,219 -- 14,787
Borrowings under MARAD loan facility..................... 43,899 59,494 40,054
Repayment of MARAD borrowings............................ (1,318) -- --
Borrowing on line of credit.............................. 52,591 -- --
Borrowings on term loan.................................. 29,270 -- --
Repayment of capital leases.............................. (5,183) -- --
Exercise of stock options, net........................... 5,900 4,084 2,980
Purchase of treasury stock............................... -- (2,575) --
--------- --------- --------
Net cash provided by financing activities........ 212,378 61,003 57,821
--------- --------- --------
Effect of exchange rate changes on cash and cash
equivalents.............................................. 106 -- --
Net increase (decrease) in cash and cash equivalents....... (37,123) (7,715) 33,528
Cash and cash equivalents:
Balance, beginning of year............................... 37,123 44,838 11,310
--------- --------- --------
Balance, end of year..................................... $ -- $ 37,123 $ 44,838
========= ========= ========
The accompanying notes are an integral part of these consolidated financial
statements.
44
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, is an energy services company specializing in subsea
construction and well operation. CDI operates primarily in the Gulf of Mexico
(Gulf), and recently in the North Sea, with services that cover the lifecycle of
an offshore oil or gas field. CDI's current diversified fleet of 23 vessels and
21 remotely operated vehicles (ROVs) and trencher systems perform services that
support drilling, well completion, intervention, construction and
decommissioning projects involving pipelines, production platforms, risers and
subsea production systems. The Company also has a significant investment in oil
and gas properties and related production facilities as part of its Production
Partnering business. CDI's customers include major and independent oil and gas
producers, pipeline transmission companies and offshore engineering and
construction firms.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of
the Company and its majority owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated. The Company accounts for its 50%
interest in Deepwater Gateway L.L.C. using the equity method of accounting as
the Company does not have voting or operational control of this entity.
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. On an ongoing basis the Company evaluates its estimates
including those related to bad debts, investments, intangible assets and
goodwill, property plant and equipment, income taxes, workers' insurance and
contingent liabilities. The Company bases its estimates on historical experience
and on various other assumptions that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgments about
the carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results could differ from those estimates.
GOODWILL AND INDEFINITE-LIVED INTANGIBLES
In accordance with Statement of Financial Accounting Standards ("SFAS") No.
142, Goodwill and Indefinite-Lived Intangibles ("SFAS No. 142"), the Company
tests for the impairment of goodwill and other intangible assets with indefinite
lives on at least an annual basis. The Company's goodwill impairment test
involves a comparison of the fair value of each of the Company's reporting
units, as defined under SFAS No. 142, with its carrying amount. The Company's
indefinite-lived asset impairment test involves a comparison of the fair value
of the intangible and its carrying value. The fair value is determined using
discounted cash flows and other market-related valuation models, such as
earnings multiples and comparable asset market values. Prior to the adoption of
SFAS No. 142, goodwill was amortized on a straight line basis over 25 years. In
conjunction with the adoption of this statement, the Company has discontinued
the amortization of goodwill.
PROPERTY AND EQUIPMENT
Property and equipment, both owned and under capital leases, are recorded
at cost. Depreciation is provided primarily on the straight-line method over the
estimated useful lives of the assets.
45
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
All of the Company's interests in oil and gas properties are located
offshore in United States waters. The Company follows the successful efforts
method of accounting for its interests in oil and gas properties. Under the
successful efforts method, the costs of successful wells and leases containing
productive reserves are capitalized. Costs incurred to drill and equip
development wells, including unsuccessful development wells, are capitalized.
Energy Resource Technology, Inc. ("ERT") acquisitions of producing offshore
properties are recorded at the value exchanged at closing together with an
estimate of its proportionate share of the undiscounted decommissioning
liability assumed in the purchase based upon its working interest ownership
percentage. In estimating the decommissioning liability assumed in offshore
property acquisitions, the Company performs detailed estimating procedures,
including engineering studies. All capitalized costs are amortized on a unit-of-
production basis (UOP) based on the estimated remaining oil and gas reserves.
Properties are periodically assessed for impairment in value, with any
impairment charged to expense.
The following is a summary of the components of property and equipment
(dollars in thousands):
ESTIMATED
USEFUL LIFE 2002 2001
----------- -------- --------
Construction in progress............................. N/A $ 32,943 $221,916
Vessels.............................................. 15 to 30 465,158 103,929
Offshore leases and equipment........................ UOP 210,542 82,334
Machinery, equipment and leasehold improvements...... 5 18,235 15,563
-------- --------
Total property and equipment....................... $726,878 $423,742
======== ========
In July 1999, the CDI Board of Directors approved the construction of the
Q4000, a newbuild, ultra-deepwater multi-purpose vessel, for a total estimated
cost of $150 million and, in June 2001, approved modification to the original
construction contract increasing the total estimated costs to $182 million.
Amounts incurred on this project and the conversion of the Intrepid pipelay
vessel were included in Construction in Progress as of December 31, 2001. Both
of these vessels were placed in service during 2002 and are included in Vessels
as of December 31, 2002. Construction in progress as of December 31, 2002
includes costs incurred relating to construction of the spar at Gunnison (see
note 9). The Company capitalized interest totaling $4.4 million and $1.9 million
during the years ended December 31, 2002 and 2001, respectively. During 2001,
the Company acquired two additional DP marine construction vessels (the Mystic
Viking and the Eclipse). The total cost of the two vessels acquired and related
upgrades was approximately $40 million, the majority of which was expended and
capitalized as of December 31, 2001.
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 $11,489,000, $8,501,000 and $4,343,000 for
the years ended December 31, 2002, 2001 and 2000, respectively.
In accordance with SFAS No. 144, Accounting for the Impairment or Disposal
of Long-Lived Assets, long-lived assets, excluding goodwill and indefinite-lived
intangibles, to be held and used by the Company are reviewed to determine
whether any events or changes in circumstances indicate that the carrying amount
of the asset may not be recoverable. SFAS No. 144 modifies SFAS No. 121,
Accounting for the Impairment or Disposal of Long-Lived Assets to be Disposed
of. For long-lived assets to be held and used, the Company bases its evaluation
on impairment indicators such as the nature of the assets, the future economic
benefit of the assets, any historical or future profitability measurements and
other external market conditions or factors that my be present. If such
impairment indicators are present or other factors exist that indicate that the
carrying amount of the asset may not be recoverable, the Company determines
whether an impairment has occurred through the use of an undiscounted cash flows
analysis of the asset at the lowest level for which identifiable cash flows
exist. If an impairment has occurred, the Company recognizes a loss for the
difference between the
46
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
carrying amount and the fair value of the asset. The fair value of the asset is
measured using quoted market prices or, in the absence of quoted market prices,
is based on an estimate of discounted cash flows. Assets are classified as held
for sale when the Company has a plan for disposal of certain assets and those
assets meet the held for sale criteria of SFAS No. 144.
FOREIGN CURRENCY
The functional currency for the Company's foreign subsidiary Well Ops
(U.K.) Limited is the applicable local currency (British Pound). Results of
operations for this subsidiary are translated into U.S. dollars using average
exchange rates during the period. Assets and liabilities of this foreign
subsidiary are translated into U.S. dollars using the exchange rate in effect at
the balance sheet date and the resulting translation adjustment, which was a
gain of $2.5 million, net of taxes of $1.4 million, in 2002 is included as
accumulated other comprehensive loss, as a component of shareholders' equity.
All foreign currency transaction gains and losses are recognized currently in
the statements of operations. These amounts for the year ended December 31, 2002
were not material to the Company's results of operations or cash flows.
Canyon Offshore, the Company's ROV and robotics subsidiary, has operations
in the United Kingdom and Southeast Asia sectors. Canyon conducts the majority
of its affairs in these regions in U.S. dollars which it considers the
functional currency. When currencies other than the U.S. dollar are to be paid
or received the resulting gain or loss from translation is recognized in the
statements of operations. These amounts for the year ended December 31, 2002
were not material to the Company's results of operations or cash flows.
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES
The Company's price risk management activities involve the use of
derivative financial instruments to hedge the impact of market price risk
exposures primarily related to our oil and gas production. Under SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, all derivatives
are reflected in our balance sheet at their fair market value.
Under SFAS No. 133 there are two types of hedging activities: hedges of
cash flow exposure and hedges of fair value exposure. The Company engages
primarily in cash flow hedges. Hedges of cash flow exposure are entered into to
hedge a forecasted transaction or the variability of cash flows to be received
or paid related to a recognized asset or liability. Changes in the derivative
fair values that are designated as cash flow hedges are deferred to the extent
that they are effective and are recorded as a component of accumulated other
comprehensive income until the hedged transactions occur and are recognized in
earnings. The ineffective portion of a cash flow hedge's change in value is
recognized immediately in earnings in oil and gas production revenues.
As required by SFAS No. 133, we formally document all relationships between
hedging instruments and hedged items, as well as our risk management objectives,
strategies for undertaking various hedge transactions and our methods for
assessing and testing correlation and hedge ineffectiveness. All hedging
instruments are linked to the hedged asset, liability, firm commitment or
forecasted transaction. We also assess, both at the inception of the hedge and
on an on-going basis, whether the derivatives that are used in our hedging
transactions are highly effective in offsetting changes in cash flows of the
hedged items. We discontinue hedge accounting prospectively if we determine that
a derivative is no longer highly effective as a hedge.
The market value of hedging instruments reflects our best estimate and is
based upon exchange or over-the-counter quotations whenever they are available.
Quoted valuations may not be available due to location differences or terms that
extend beyond the period for which quotations are available. Where quotes are
not available, we utilize other valuation techniques or models to estimate
market values. These modeling techniques require us to make estimations of
future prices, price correlation and market volatility and liquidity. Our actual
results may differ from our estimates, and these differences can be positive or
negative.
47
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During the second half of 2002, the Company entered into various cash flow
hedging swap contracts to fix cash flows relating to a portion of the Company's
oil and gas production. All of these qualified for hedge accounting and none
extended beyond a year and a half. The aggregate fair value of the hedges was a
liability of $4.1 million as of December 31, 2002. The Company recorded $2.6
million of loss, net of taxes of $1.4 million, in other comprehensive loss
within shareholders' equity as these hedges were highly effective.
As of December 31, 2002, the Company has the following volumes under
derivative contracts related to its oil and gas producing activities:
INSTRUMENT AVERAGE WEIGHTED
PRODUCTION PERIOD TYPE MONTHLY VOLUMES AVERAGE PRICE
----------------- ---------- --------------- -------------
Crude Oil:
January -- December 2003........................ Swap 46 MBbl $26.50
January -- December 2003........................ Swap 30 MBbl $26.82
Natural Gas:
January -- March 2003........................... Swap 800,000 MMBtu $ 4.21
April -- December 2003.......................... Swap 400,000 MMBtu $ 4.02
April -- December 2003.......................... Swap 200,000 MMBtu $ 4.21
Subsequent to December 31, 2002, the Company entered into additional
natural gas hedges for the period April through December 2003. The contracts
cover 200,000 MMBtu per month at $4.97.
In June 2002, CDI signed an agreement with Coflexip to acquire the Subsea
Well Operations Business Unit for 44.8 million British pounds (which at the time
equaled $67.5 million) which subsequently closed in July. CDI entered into a
foreign currency forward contract to lock in the British pound to U.S. dollar
exchange rate. Under SFAS No. 133, we accounted for this transaction with
changes in its fair value reported in earnings. Accordingly, a $1.1 million gain
was recorded in other income for the year ended December 31, 2002 as a result of
the change in market value of the contract as of June 30, 2002. This contract
settled in July 2002 for $1.1 million.
EARNINGS PER SHARE
The Company computes and presents earnings per share in accordance with
SFAS No. 128, Earnings Per Share. SFAS 128 requires the presentation of "basic"
EPS and "diluted" EPS on the face of the statement of operations. Basic EPS is
computed by dividing the net income available to common shareholders by the
weighted-average shares of outstanding common stock. The calculation of diluted
EPS is similar to basic EPS except that the denominator includes dilutive common
stock equivalents, which were stock options, less the number of treasury shares
assumed to be purchased from the proceeds with the exercise of stock options.
STOCK BASED COMPENSATION PLANS
In December 2002, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 148, Accounting for Stock-Based Compensation Transition and
Disclosure("SFAS No. 148") to provide alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. As permitted under SFAS No. 123, the Company continues to
use the intrinsic value method of accounting established by Accounting
Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, to
account for its stock-based compensation programs. Accordingly, no compensation
expense is recognized when the exercise price of an employee stock option is
equal to the Common Share market price on the grant date. If SFAS No. 123 had
been used for the accounting of these plans, the Company's pro forma net income
for 2002, 2001 and 2000 would have been $7.9 million, $25.9 million and $21.7
million, respectively, and the Company's pro forma diluted earnings per share
would have been $0.22,
48
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$0.79 and $0.67, 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.
For the purposes of pro forma disclosures, the fair value of each option
grant is estimated on the date of grant using the Black-Scholes option pricing
model with the following weighted average assumptions used: expected dividend
yields of 0 percent; expected lives ranging from three to ten years, risk-free
interest rate assumed to be 5.0 percent in 2000, 4.5 percent in 2001 and 4.0
percent in 2002, and expected volatility to be 62 percent in 2000, 61 percent in
2001 and 59 percent in 2002. The fair value of shares issued under the Employee
Stock Purchase Plan was based on the 15% discount received by the employees. The
weighted average per share fair value of the options granted in 2002, 2001 and
2000 was $15.20, $14.47, and $8.05, respectively. The estimated fair value of
the options is amortized to pro forma expense over the vesting period.
REVENUE RECOGNITION
The Company earns the majority of its subsea service and salvage
contracting revenues during the summer and fall months. Revenues are derived
from billings under contracts (which are typically of short duration) that
provide for either lump-sum turnkey charges or specific time, material and
equipment charges which are billed in accordance with the terms of such
contracts. The Company recognizes revenue as it is earned at estimated
collectible amounts. Revenue on significant turnkey contracts is recognized on
the percentage-of-completion method based on the ratio of costs incurred to
total estimated costs at completion. Contract price and cost estimates are
reviewed periodically as work progresses and adjustments are reflected in the
period in which such estimates are revised. Provisions for estimated losses on
such contracts are made in the period such losses are determined. Unbilled
revenue represents revenue attributable to work completed prior to year-end
which has not yet been invoiced. All amounts included in unbilled revenue at
December 31, 2002 are expected to be billed and collected within one year.
The Company records revenues from the sales of crude oil and natural gas
when delivery to the customer has occurred and title has transferred. This
occurs when production has been delivered to a pipeline or a barge lifting has
occurred. The Company may have an interest with other producers in certain
properties. In this case the Company used the entitlements method to account for
sales of production. Under the entitlements method the Company may receive more
or less than its entitled share of production. If the Company receives more than
its entitled share of production, the imbalance is treated as a liability. If
the Company receives less than its entitled share, the imbalance is recorded as
an asset.
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 allowed under the
terms of the related contract but are outside the scope of the original quote.
The Company establishes a revenue allowance for these additional billings based
on its collections history if conditions warrant such a reserve.
MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK
The market for the Company's products and services is primarily 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: 2002 -- BP Trinidad & Tobago LLC (11%); Horizon
Offshore, Inc. (10%); 2001 -- Horizon Offshore, Inc. (18%), Enron Corp. (10%);
and 2000 -- Enron Corp. (13%).
49
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In March 2001, CDI and Horizon Offshore, Inc. announced that the Alliance
Agreement covering operation on the Outer Continental Shelf was extended for a
three-year period. Principal features of the Alliance are that CDI provides Dive
Support Vessel services behind Horizon pipelay barges while Horizon supplies
pipelay, derrick barge and heavy lift capacity to Cal Dive. The Alliance was
also expanded to include CDI providing the diving personnel working from Horizon
barges, a service Horizon handled internally in 2000. During 2001 and 2002 the
Company also provided dynamically positioned vessels to support Horizon projects
for Pemex in Mexican waters of the Gulf of Mexico.
INCOME TAXES
Deferred income taxes are based on the differences between financial
reporting and the tax bases of assets and liabilities 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. Income taxes have
been provided based upon the tax laws and rates in the countries in which
operations are conducted and income is earned. A valuation allowance for
deferred tax assets is recorded when it is more likely than not that some or all
of the benefit from the deferred tax asset will not be realized.
DEFERRED DRYDOCK CHARGES
The Company accounts for regulatory (U.S. Coast Guard, American Bureau of
Shipping and Det Norske Veritas) related drydock inspection and certification
expenditures by capitalizing the related costs and amortizing them over the
30-month period between regulatory mandated drydock inspections and
certification. During the years ended December 31, 2002, 2001 and 2000, drydock
amortization expense was $4.9 million, $3.1 million and $2.2 million,
respectively. This predominant industry practice provides appropriate matching
of expenses with the period benefitted (i.e., certification to operate the
vessel for a 30-month period).
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. The
Company had $2.5 million of restricted cash as of December 31, 2002 representing
amounts securing a performance bond which management believes will be released
during 2003. During the years ended December 31, 2002, 2001 and 2000, the
Company made cash payments for interest charges, net of interest capitalized, of
$811,000, $662,000 and $-0-, respectively, and made cash payments for federal
income taxes of approximately $-0-, $-0- and $1,800,000 respectively.
RECLASSIFICATIONS
Certain reclassifications were made to previously reported amounts in the
consolidated financial statements and notes to make them consistent with the
current presentation format.
NEW REPORTING REQUIREMENTS
In July 2001, the FASB released SFAS No. 143, Accounting for Asset
Retirement Obligations, which is required to be adopted no later than January 1,
2003. SFAS 143 addresses the financial accounting and reporting obligations and
retirement costs related to the retirement of tangible long-lived assets. Among
other things, SFAS 143 will require oil and gas companies to reflect
decommissioning liabilities on the face of the balance sheet at fair market
value on a discounted basis. Historically, ERT has reflected this liability on
the balance sheet on an undiscounted basis. The Company will adopt this
standard, as required, effective January 1, 2003. Management currently believes
adoption of this standard will result in a cumulative effect adjustment in the
first quarter of 2003 of between $0.01 and $0.03 per share and adjustments to
certain balance sheet accounts including a decrease in Decommissioning
Liabilities of approximately $30 million due to discounting.
50
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In November 2002, FASB interpretation ("FIN") No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others ("FIN No. 45") was issued. FIN No. 45
requires a guarantor to recognize at the inception of a guarantee a liability
for the fair value of the obligation undertaken in issuing the guarantee. FIN
No. 45 also expands the disclosures required to be made by a guarantor about its
obligations under certain guarantees that it has issued. Initial recognition and
measurement provisions of FIN No. 45 are applicable on a prospective basis to
guarantees issued or modified. The disclosure requirements are effective
immediately. Adoption of FIN No. 45 did not have a material effect on CDI's
consolidated financial statements.
In January 2003, FIN No. 46, Consolidation of Variable Interest Entities
was issued. FIN No. 46 requires that companies that control another entity
through interests other than voting interests should consolidate the controlled
entity. FIN No. 46 applies immediately to variable interest entities created
after January 31, 2003, and applies in the first interim period beginning after
June 15, 2003 to variable interest entities created before February 1, 2003. The
related disclosure requirements are effective immediately. The Company does not
believe that the adoption of this interpretation will have a material impact on
its consolidated financial statements.
3. OFFSHORE PROPERTY TRANSACTIONS
In August 2002 ERT, a wholly owned subsidiary of Cal Dive International,
Inc. acquired the 74.8% working interest of Shell Exploration & Production
Company in the South Marsh Island 130 (SMI 130) field (Shell acquisition). ERT
paid $10.3 million in cash and assumed Shell's pro-rata share of the related
decommissioning liability. SMI 130 consists of two blocks, located in
approximately 215 feet of water, with approximately 155 wells on five 8-pile
platforms. Unaudited pro forma combined operating results of CDI and the Shell
acquisition for the twelve months ended December 31, 2002 and 2001, respectively
are summarized as follows (in thousands, except per share data):
2002 2001
-------- --------
(UNAUDITED)
Net revenues................................................ $321,186 $259,762
Income before taxes......................................... 23,690 54,892
Net income.................................................. 15,399 35,828
Earnings per share:
Basic..................................................... $ 0.43 $ 1.10
Diluted................................................... 0.43 1.08
In August 2002, ERT also completed the purchase of seven Gulf of Mexico
fields from Amerada Hess (including its 25% ownership position in SMI 130) for
$9.3 million in cash and assumption of Amerada Hess's pro-rata share of the
related decommissioning liability. As a result, ERT took over as operator with
an effective 100% working interest in that field.
In June 2002, ERT acquired a package of offshore properties from Williams
Exploration and Production. ERT paid $4.9 million and assumed the pro-rata share
of the abandonment obligation for the acquired interests. The blocks purchased
represent an average 30% net working interest in 26 Gulf of Mexico leases.
In April 2002, ERT acquired a 100% interest in East Cameron Block 374,
including existing wells, equipment and improvements. Terms included a cash
payment of approximately $3 million to reimburse the owners for the
inception-to-date cost of the subsea wellhead and umbilical, and an overriding
royalty interest in future production. Cal Dive completed the temporarily
abandoned number one well and performed a subsea tie-back to a host platform.
The cost of completion and tie-back was approximately $7 million, with first
production occurring in August 2002.
51
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ERT purchased working interests of 3% to 75% in four offshore blocks during
2001 in exchange for assumption of the pro-rata share of the decommissioning
obligations. In addition, during 2001 ERT purchased a working interest of 55% in
Vermilion 201 for $2.5 million (see footnote 4). In the first quarter of 2000,
ERT acquired interests in six offshore blocks with working interests from 40% to
75% in five platforms, one caisson and 13 wells. ERT agreed to a purchase price
of $4.9 million and assumed the prorated share of the abandonment obligation for
the acquired interests, and entered into a two-year contract to manage certain
properties. Additionally, in April 2000, ERT acquired a 20% interest in
Gunnison. See further discussion in footnote 4. In connection with 2002, 2001
and 2000 offshore property acquisitions, ERT assumed net abandonment liabilities
estimated at approximately $63.6 million, $3.1 million and $4.2 million
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 $9.2 million, $15.2 million and $11.7
million for the years ended 2002, 2001 and 2000, respectively. In accordance
with federal regulations that require operators in the Gulf of Mexico to post an
area wide bond of $3 million, the MMS has allowed the Company to fulfill such
bonding requirements through an insurance policy.
During each of the past three years ERT has sold its interests in certain
fields as well as the platforms and a pipeline. An ERT operating policy provides
for the sale of assets when the expected future revenue stream can be
accelerated in a single transaction. The net result of these sales had no impact
for the year ended December 31, 2002 and added two cents and four cents to
diluted earnings per share for the years ending December 31, 2001 and 2000,
respectively. These sales were structured as Section 1031 "Like Kind" exchanges
for tax purposes. Accordingly, the cash received was restricted to use for
subsequent acquisitions of additional oil and gas properties.
4. RELATED PARTY TRANSACTIONS
In April 2000, ERT acquired a 20% working interest in Gunnison, a Deepwater
Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corporation. Consistent with
CDI's philosophy of avoiding exploratory risk, financing for the exploratory
costs of approximately $20 million was provided by an investment partnership
(OKCD Investments, Ltd.), the investors of which are CDI senior management, in
exchange for an overriding royalty interest of 25% of CDI's 20% working
interest. CDI provided no guarantees to the investment partnership. The Board of
Directors established three criteria to determine a commercial discovery and the
commitment of Cal Dive funds: 75 million barrels (gross) of reserves, total
development costs of $500 million consistent with 75 MBOE, and a CDI estimated
shareholder return of no less than 12%. Kerr-McGee, the operator, drilled
several exploration wells and sidetracks in 3,200 feet of water at Garden Banks
667, 668 and 669 (the Gunnison prospect) and encountered significant potential
reserves resulting in the three criteria being achieved during 2001. With the
sanctioning of a commercial discovery, the Company is funding ongoing
development and production costs. Cal Dive's share of such project development
costs is estimated in a range of $100 million to $110 million ($63.3 million of
which had been incurred by December 31, 2002) with over half of that for
construction of the spar. See footnote 9 for discussion of financing relating to
the spar construction.
During the fourth quarter of 2000 another investment partnership composed
of Company management and industry sources funded the drilling of a deep
exploratory well at ERT's Vermilion 201 field. Effective January 1, 2001, ERT
acquired approximately 55% of this investment partnership's interest in the
reserves discovered for $2.5 million.
As part of the process of obtaining funding for the exploratory costs of
the above projects, several outside third parties were solicited. Management
believes that the structure of these transactions was both consistent
52
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
with the guidelines and at least as favorable to the Company and ERT as could
have been obtained from the third parties.
During 2002 and 2001, the Company was paid fees of $200,000 and $500,000,
respectively, by Ocean Energy, Inc. ("Ocean"), an oil and gas industry customer
of subsea services. A member of the Company's board of directors, is a member of
senior management of Ocean.
5. ACQUISITION OF BUSINESSES
CANYON OFFSHORE, INC.
In January 2002, CDI purchased Canyon, a supplier of remotely operated
vehicles (ROVs) and robotics to the offshore construction and telecommunications
industries. CDI purchased Canyon for cash of $52.8 million, the assumption of
$9.0 million of Canyon debt (offset by $3.1 million of cash acquired), 181,000
shares of CDI common stock valued at $4.3 million (143,000 shares of which we
purchased as treasury shares during the fourth quarter of 2001) and a commitment
to purchase the redeemable stock in Canyon at a price to be determined by
Canyon's performance during the years 2002 through 2004 from continuing
employees at a minimum purchase price of $13.53 per share (or $7.5 million). As
they are employees, amounts paid, if any, in excess of the $13.53 per share will
be recorded as compensation expense. No such expense was recorded in 2002. These
remaining shares have been classified as redeemable stock in subsidiary in the
accompanying balance sheet and will be adjusted to their estimated redemption
value at each reporting period based on Canyon's performance. The acquisition
was accounted for as a purchase with the acquisition price allocated to the
assets acquired and liabilities assumed based upon their estimated fair values,
with the excess being recorded as goodwill. The allocation of the $70.5 million
purchase price was as follows: ROVs and equipment ($22.9 million); net working
capital assumed ($4.0 million) and goodwill ($43.6 million). The results of
Canyon are included in the accompanying statements of operations since the date
of the purchase, January 2, 2002.
WELL OPS (U.K.) LIMITED
In July 2002, CDI purchased the subsea well operations business unit of CSO
Ltd., a wholly owned subsidiary of Technip-Coflexip, for approximately $72.0
million ($68.6 million cash and $3.4 million deferred tax liability assumption).
Well Ops (U.K.) Limited performs life of field well operations and marine
construction tasks primarily in the North Sea. The assets purchased include the
Seawell (a 368-foot DPDSV capable of supporting manned diving, ROVs and well
operations). The acquisition was accounted for as a business purchase with the
acquisition price allocated to the assets acquired and liabilities assumed based
upon their estimated fair values, with the excess being recorded as goodwill.
During the fourth quarter of 2002 the Company completed its purchase price
allocation, including obtaining an appraisal of the Seawell,resulting in $50
million allocated to this vessel $1.5 million allocated to patented technology
(to be amortized over 20 years) and goodwill of approximately $20.6 million as
of December 31, 2002. The results of Well Ops (U.K.) are included in the
accompanying statements of operations since the date of the purchase, July 1,
2002.
PROFESSIONAL DIVERS OF NEW ORLEANS, INC. (PDNO)
In March 2001, CDI acquired substantially all of the assets of Professional
Divers of New Orleans, Inc. (PDNO) in exchange for $11.5 million. The assets
purchased included a 165-foot four-point moored DSV, the Mr. Sonny, three
utility vessels and associated diving equipment including two saturation diving
systems. This acquisition was accounted for as a purchase with the acquisition
price of $11.5 million being allocated to the assets acquired and liabilities
assumed based upon their estimated fair values with the balance of the purchase
price ($2.8 million) being recorded as goodwill. Total goodwill relating to
shallow water diving company acquisitions (i.e., PDNO and Aquatica) was $15
million as of December 31, 2002.
53
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The 2002 and 2001 acquisitions presented above are not material
individually or in the aggregate with same year acquisitions, therefore pro
forma information is not presented.
6. EQUITY INVESTMENT IN DEEPWATER GATEWAY L.L.C.
In June 2002 CDI, along with El Paso Energy Partners, formed Deepwater
Gateway L.L.C. (a 50/50 venture) to design, construct, install, own and operate
a tension leg platform ("TLP") production hub primarily for Anadarko Petroleum
Corporation's Marco Polo field discovery in the Deepwater Gulf of Mexico. CDI's
share of the construction costs is estimated to be approximately $110 million.
In August 2002 the Company, along with El Paso, completed a non-recourse project
financing for this venture, terms of which include a minimum CDI equity
investment of $33 million, all of which had been paid as of December 31, 2002.
This is recorded as Investment in Deepwater Gateway L.L.C. in the accompanying
consolidated balance sheet. Terms of the financing also require CDI to guarantee
a balloon payment due at the end of the financing term in 2008 (estimated to be
$22.5 million). The Company has not recorded any liability for this guarantee as
management believes it is unlikely the Company will be required to pay the
balloon payment.
7. GOODWILL
In June 2001, the FASB issued SFAS No. 142, which provides for the
non-amortization of goodwill and other intangible assets with indefinite lives
and requires that such assets be tested for impairment at least on an annual
basis. The impact of adopting SFAS No. 142 would have been immaterial to the
Company's results of operations for the years ended December 31, 2001 and 2000,
respectively. The Company adopted SFAS No. 142 effective January 1, 2002 and has
applied the non-amortization provision. During the second quarter of 2002, the
Company completed the transitional goodwill impairment test prescribed in SFAS
No. 142 with respect to existing goodwill at the date of adoption. In addition,
the Company completed its annual goodwill impairment test as of November 1,
2002. The Company's goodwill impairment test involves a comparison of the fair
value of each of the Company's reporting units, as defined under SFAS No. 142,
with its carrying amount. All of the Company's goodwill as of December 31, 2002
and 2001 related to its subsea and salvage segment. The fair value is determined
using discounted cash flows and other market-related valuation models. As both
calculations indicated that the fair value of each reporting unit exceeded its
carrying amount, none of the Company's goodwill was impaired. The Company will
continue to test its goodwill annually on a consistent measurement date unless
events occur or circumstances change between annual tests that would more likely
than not reduce the fair value of a reporting unit below its carrying amount.
8. ACCRUED LIABILITIES
Accrued liabilities consisted of the following as of December 31, 2002 and
2001 (in thousands):
2002 2001
------- -------
Accrued payroll and related benefits........................ $ 6,874 $ 6,880
Workers' compensation claims................................ 1,724 1,537
Workers' compensation claims to be reimbursed............... 5,534 6,276
Royalties payable........................................... 3,238 3,207
Hedging liability........................................... 4,064 --
Other....................................................... 13,356 3,111
------- -------
Total accrued liabilities................................. $34,790 $21,011
======= =======
54
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. LONG-TERM DEBT
In August 2000, the Company closed a $138.5 million long-term financing for
construction of the Q4000. This U.S. Government guaranteed financing is pursuant
to Title XI of the Merchant Marine Act of 1936 which is administered by the
Maritime Administration ("MARAD Debt"). In January 2002, the Maritime
Administration agreed to expand the facility to $160 million to include the
modifications to the vessel which had been approved during 2001. To date the
Company has drawn $143.5 million on this facility, which approximates the
maximum of qualified expenditures. The MARAD Debt is payable in equal
semi-annual installments beginning in August 2002 and maturing 25 years from
such date. It is collateralized by the Q4000, with CDI guaranteeing 50% of the
debt, and bears interest at a rate which currently floats at a rate
approximating AAA Commercial Paper yields plus 20 basis points (approximately 2%
as of December 31, 2002). For a period up to ten years from delivery of the
vessel in April 2002, CDI has options to lock in a fixed rate. In accordance
with the MARAD Debt agreements, CDI is required to comply with certain covenants
and restrictions, including the maintenance of minimum net worth, working
capital and debt-to-equity requirements. As of December 31, 2002 the Company was
in compliance with these covenants.
The Company has a revolving credit facility ("Revolver") which was
increased from $40 million to $70 million during 2002 and the term extended for
three years. This facility is collateralized by accounts receivable and most of
the remaining vessel fleet, bears interest at LIBOR plus 125-250 basis points
depending on CDI leverage ratios (approximately 4.2% as of December 31, 2002)
and, among other restrictions, includes three financial covenants (cash flow
leverage, minimum interest coverage and fixed charge coverage). As of December
31, 2002, the Company had drawn $52.6 million under this revolving credit
facility and was in compliance with these covenants with the exception of the
cash flow leverage covenant, for which the Company obtained a waiver.
In November 2001, ERT entered into a five-year lease transaction with an
entity owned by a third party to fund CDI's portion of the construction costs
($67 million) of the spar for the Gunnison field. As of December 31, 2001 and
June 30, 2002, the entity had drawn down $5.6 million and $22.8 million,
respectively, on this facility. Accrued interest cost on the outstanding balance
is capitalized to the cost of the facility during construction and is payable
monthly thereafter. In August 2002, CDI acquired 100% of the equity of the
entity and converted the notes into a term loan ("Gunnison Term Loan"). The
total commitment of the loan was reduced to $35 million and will be payable in
quarterly installments of $1.75 million for three years after delivery of the
spar with the remaining $15.75 million due at the end of the three years. The
facility bears interest at LIBOR plus 225-300 basis points depending on CDI
leverage ratios (approximately 4.4% as of December 31, 2002) and includes, among
other restrictions, three financial covenants (cash flow leverage, minimum
interest coverage and debt to total book capitalization). The Company was in
compliance with these covenants as of December 31, 2002 with the exception of
the cash flow leverage covenant, for which the Company obtained a waiver. The
debt ($29.3 million at December 31, 2002) and related asset have been reflected
on CDI's balance sheet beginning in the third quarter of 2002. The purchase
price was allocated entirely to construction in progress as the purchase price
approximated the fair value of the spar.
55
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Scheduled maturities of Long-term Debt outstanding as of December 31, 2002
were as follows (in thousands):
GUNNISON
MARAD DEBT REVOLVER TERM LOAN OTHER TOTAL
---------- -------- --------- ------- --------
2003........................... $ 2,766 $ -- $ -- $ 1,435 $ 4,201
2004........................... 2,949 -- 7,000 1,395 11,344
2005........................... 3,144 52,591 7,000 572 63,307
2006........................... 3,352 -- 15,270 386 19,008
2007........................... 3,573 -- -- -- 3,573
Thereafter..................... 126,344 -- -- -- 126,344
-------- ------- ------- ------- --------
Long-term debt................. 142,128 52,591 29,270 3,788 227,777
Current maturities............. (2,766) (--) (--) (1,435) (4,201)
-------- ------- ------- ------- --------
Long-term debt, less current
maturities................... $139,362 $52,591 $29,270 $ 2,353 $223,576
======== ======= ======= ======= ========
10. INCOME TAXES
CDI and its subsidiaries, including acquired companies from their
respective dates of acquisition, file a consolidated U.S. federal income tax
return. The Company conducts its international operations in a number of
locations that have varying laws and regulations with regard to taxes.
Management believes that adequate provisions have been made for all taxes that
will ultimately be payable. $2.5 million of the Company's $19.0 million pre-tax
income was derived from foreign operations. Income taxes have been provided
based on the statutory rate of 35 percent adjusted for items which are allowed
as deductions for federal income tax reporting purposes, but not for book
purposes. The primary differences between the statutory rate and the Company's
effective rate are as follows:
2002 2001 2000
---- ---- ----
Statutory rate.............................................. 35% 35% 35%
Foreign provision........................................... 4 -- --
Foreign tax credit.......................................... (4) -- --
Research and development tax credits........................ -- (2) (2)
Other....................................................... -- 2 1
-- -- --
Effective rate............................................ 35% 35% 34%
== == ==
Components of the provision for income taxes reflected in the statements of
operations consist of the following (in thousands):
2002 2001 2000
------ ------- -------
Current.................................................. $ 534 $ -- $ --
Deferred................................................. 6,130 15,504 11,555
------ ------- -------
$6,664 $15,504 $11,555
====== ======= =======
56
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2002 2001 2000
------ ------- -------
Domestic................................................. $5,996 $15,504 $11,555
Foreign.................................................. 668 -- --
------ ------- -------
$6,664 $15,504 $11,555
====== ======= =======
Deferred income taxes result from differences between the tax bases of
assets and liabilities and their carrying value. The nature of these differences
and the income tax effect of each as of December 31, 2002 and 2001, is as
follows (in thousands):
2002 2001
-------- --------
Deferred tax liabilities -- Depreciation and other.......... $102,230 $ 75,805
Deferred tax assets --
Net operating loss carryforward........................... (28,385) (13,761)
R&D credit carryforward................................... (17,087) (15,987)
Reserves, accrued liabilities and other................... (9,929) (7,548)
Valuation allowance (R&D credit).......................... 14,450 13,528
-------- --------
Net deferred tax liability............................. $ 61,279 $ 52,037
======== ========
The detail of deferred tax balances as of December 31, 2001 described above
contain reclassification adjustments totaling $21.2 million and conforming
disclosures to provide a detail of deferred tax assets that were previously
offset against deferred tax liabilities. The Company's consolidated balance
sheet as of December 31, 2001 has been adjusted to conform with the above
presentation.
CDI effectively paid no federal income taxes in 2002 and 2001 due primarily
to the deduction of Q4000 construction costs as research and development for
federal tax purposes. The Company paid $1.8 million of federal income taxes
during 2000, but the amount was refunded in January 2001 upon completing our
research and development analysis and filing for the refund. In addition, we
filed amended tax returns for 1998 and 1999, deducting such costs, resulting in
refunds of $8.2 million which were collected in January 2001.
The Company has provided additional taxes for the anticipated repatriation
of earnings of its foreign subsidiaries.
At December 31, 2002, the Company had $81.1 million of net operating
losses. Loss carryforwards, if not utilized, will expire at various dates from
2019 through 2022.
11. COMMITMENTS AND CONTINGENCIES:
LEASE COMMITMENTS
During 1999, CDI acquired an interest in Cal Dive Aker CAHT I, L.L.C. (CAHT
I), the company which owned the Cal Dive Aker Dove (a newbuild DP anchor
handling and subsea construction vessel which commenced operations in September
1999) for a total of $18.9 million. CDI effectively owned 56% of CAHT I and,
accordingly, results of operations of this company were consolidated in the
accompanying financial statements with Aker's share being reflected as minority
interest. In December, 1999 CAHT I entered into a sale-leaseback of the Cal Dive
Aker Dove. Cal Dive's portion of the sale proceeds received totaled $20 million.
The lease was accounted for as an operating lease. Effective April 1, 2001,
Coflexip's acquisition of Aker enabled CDI to "put" its interest in CAHT I back
to Aker in return for Aker assuming all of CDI's obligations and guarantees
under the sale-leaseback.
57
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company leases several facilities, ROVs and a vessel under
noncancelable operating leases, with the more significant leases expiring in the
years 2004 and 2005. Future minimum rentals under these leases are $19,018,000
at December 31, 2002 with $8,848,000 due in 2003, $7,033,000 in 2004, $2,198,000
in 2005, $276,000 in 2006, $276,000 in 2007 and $387,000 thereafter. Total
rental expense under these operating leases was $6,885,000, $779,000 and
$721,000 for the years ended December 31, 2002, 2001 and 2000, respectively.
INSURANCE
The Company carries Hull and Increased Value insurance which provides
coverage for physical damage to an agreed amount for each vessel. The
deductibles are based on the value of the vessel with a maximum deductible of
$500,000 on the Q4000. Other vessels carry deductibles between $100,000 and
$350,000. The Company also carries Protection and Indemnity insurance which
covers liabilities arising from the operation of the vessel and General
Liability insurance which covers liabilities arising from construction
operations. The deductible on both the P&I and General Liability is $100,000 per
occurrence. Onshore employees are covered by Workers' Compensation. Offshore
employees, including divers and tenders and marine crews, are covered by an
Excess Maritime Employers Liability insurance policy which covers Jones Act
exposures and includes a deductible of $100,000 per occurrence plus a $1 million
annual aggregate. In addition to the liability policies named above, the Company
carries various layers of Umbrella Liability for total limits of $200,000,000
excess of primary for all vessels. The Company's self insured retention on its
medical and health benefits program for employees is $100,000 per claim.
In June 2000, the DP DSV Balmoral Sea caught fire while dockside in New
Orleans, Louisiana as the vessel was being prepared to enter drydock for an
extended period. The vessel was deemed a total loss by insurance underwriters.
Her book value (approximately $7 million) was fully insured as were all salvage
and removal costs. Payments from the insurance companies were received during
the fourth quarter of 2000.
The Company incurs workers' compensation claims in the normal course of
business, which management believes are covered by insurance. The Company, its
insurers and legal counsel analyze each claim for potential exposure and
estimate the ultimate liability of each claim. Amounts accrued and receivable
from insurance companies, above the applicable deductible limits, are reflected
in other current assets in the consolidated balance sheet. Such amounts were
$5,534,000 and $6,276,000 as of December 31, 2002 and 2001, respectively. See
related accrued liabilities at footnote 8. The Company has not incurred any
significant losses as a result of claims denied by its insurance carriers.
LITIGATION AND CLAIMS
The Company is involved in various routine legal proceedings primarily
involving claims for personal injury under the General Maritime Laws of the
United States and Jones Act as a result of alleged negligence. In addition, the
Company from time to time incurs other claims, such as contract disputes, in the
normal course of business. During 2002, the Company engaged in a large
construction project and, in late September, supports engineered by a
subcontractor failed resulting in over a month of downtime for two of CDI's
vessels. Management believes that under the terms of the contract the Company is
entitled to the contractual stand-by rate for the vessels during their downtime.
The customer is currently disputing these invoices along with certain other
change orders. Of the amounts billed by CDI for this project, $12.1 million had
not been collected as of February 18, 2003. Due to the size of the dispute,
inherent uncertainties with respect to an arbitration and relationship issues
with the customer, CDI provided a reserve in the fourth quarter of 2002
resulting in a loss for the Company on the project as a whole. In another
lengthy commercial dispute, EEX Corporation sued Cal Dive and others alleging
breach of fiduciary duty by a former EEX employee and damages resulting from
certain construction and property acquisition agreements. Cal Dive had responded
alleging EEX Corporation breached various provisions of the same contracts.
EEX's acquisition by Newfield during the fourth quarter 2002 enabled CDI to
enter meaningful settlement discussions prior to the trial date,
58
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
which was set for February 2003. This resulted in a settlement including CDI
making a cash payment, subsequent to yearend, and agreeing to provide work
credits for its services over the next three years. The total value of the
settlement was recorded in the Company's statement of operations for the year
ended December 31, 2002. This settlement combined with the reserves on the
project discussed above resulted in approximately $10 million of pre-tax charges
recorded in the accompanying statement of operations.
In 1998, one of our subsidiaries entered into a subcontract with Seacore
Marine Contractors Limited ("Seacore") to provide the Sea Sorceress to a
Coflexip subsidiary in Canada ("Coflexip"). Due to difficulties with respect to
the sea states and soil conditions the contract was terminated and an
arbitration to recover damages was commenced. A preliminary liability finding
has been made by the arbitrator against Seacore and in favor of the Coflexip
subsidiary. We were not a party to this arbitration proceeding. Seacore and
Coflexip settled this matter prior to the conclusion of the arbitration
proceeding with Seacore paying Coflexip $6.95 million CDN. Seacore has now made
demand on Cal Dive Offshore Ltd. ("CDO"), a subsidiary of Cal Dive, for one-half
of this amount. Because only one of the grounds in the preliminary findings by
the arbitrator is applicable to CDO, and because CDO holds substantial
counterclaims against Seacore, management believes that in the event Seacore
continues to seek contribution from our subsidiary, which would require another
arbitration, it is anticipated that our subsidiary's exposure, if any, should be
less than $500,000.
Although the above discussed matters have the potential of significant
additional liability, the Company believes that the outcome of all such matters
and proceedings will not have a material adverse effect on its consolidated
financial position, results of operations or cash flows.
12. EMPLOYEE BENEFIT PLANS
DEFINED CONTRIBUTION PLAN
The Company sponsors a defined contribution 401(k) retirement plan covering
substantially all of its employees. The Company's contributions are in the form
of cash and are determined annually as 50 percent of each employee's
contribution up to 5 percent of the employee's salary. The Company's costs
related to this plan totaled $811,000, $595,000 and $423,000 for the years ended
December 31, 2002, 2001 and 2000, respectively.
STOCK-BASED COMPENSATION PLANS
During 2000, the Board of Directors approved a "Stock Option in Lieu of
Salary Program" for the Company's Chief Executive Officer. Under the terms of
the program, the participant may annually elect to receive non-qualified stock
options (with an exercise price equal to the closing stock price on the date of
grant) in lieu of cash compensation with respect to his base salary and any
bonus earned under the annual incentive compensation program. The number of
options granted is determined utilizing the Black-Scholes valuation model as of
the date of grant with a risk premium included. The participant made such
election for 2002, 2001 and 2000 resulting in a total of 105,000, 180,000 and
115,000 options being granted during 2002, 2001 and 2000, respectively (which
includes bonuses earned under the annual incentive compensation program in 2001
and 2000).
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%
59
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
per year for a five year period or 33% per year for a three year period, have a
maximum exercise life of three, five or ten years and, subject to certain
exceptions, are not transferable.
Effective May 12, 1998, the Company adopted a qualified, non-compensatory
Employee Stock Purchase Plan ("ESPP"), which allows employees to acquire shares
of common stock through payroll deductions over a six month period. The purchase
price is equal to 85 percent of the fair market value of the common stock on
either the first or last day of the subscription period, whichever is lower.
Purchases under the plan are limited to 10 percent of an employee's base salary.
Under this plan 44,158, 38,849 and 25,391 shares of common stock were purchased
in the open market at a weighted average share price of $21.86, $22.22 and
$21.55 during 2002, 2001 and 2000, respectively.
All of the options outstanding at December 31, 2002, have exercise prices
as follows: 127,191 shares at $18.00, 111,596 at $18.06, 129,000 shares at
$19.63, 100,000 shares at $21.38, 412,000 shares at $21.83, 283,004 shares at
$21.88, 120,000 shares at $24.00, 80,000 shares at $26.75 and 627,955 shares
ranging from $3.95 to $23.72 and a weighted average remaining contractual life
of 6.11 years.
Options outstanding are as follows:
2002 2001 2000
-------------------- -------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- -------- --------- -------- --------- --------
Options outstanding,
beginning of year.... 2,179,246 $13.66 2,238,600 $11.34 1,957,208 $ 5.59
Granted................ 732,670 21.88 589,000 21.84 810,420 19.26
Exercised.............. (862,241) 7.18 (354,838) 9.43 (484,344) 4.24
Terminated............. (58,929) 15.12 (293,516) 15.69 (44,684) 4.10
--------- ------ --------- ------ --------- ------
Options outstanding,
December 31.......... 1,990,746 $19.52 2,179,246 $13.66 2,238,600 $11.34
Options exercisable,
December 31.......... 704,191 $18.76 732,787 $ 8.97 518,308 $ 7.10
========= ====== ========= ====== ========= ======
13. SHAREHOLDERS' EQUITY
The Company's amended and restated Articles of Incorporation provide for
authorized Common Stock of 120,000,000 shares with no par value per share and
5,000,000 shares of preferred stock in one or more series.
In May 2002 CDI sold 3.4 million shares of primary common stock for $23.16
per share, along with 517,000 additional shares to cover over-allotments.
During the fourth quarter of 2001, CDI purchased 143,000 shares of its
common stock for $2.6 million.
In October 2000, the Board of Directors declared a two-for-one split of
CDI's common stock in the form of a 100% stock distribution on November 13, 2000
to all holders of record at the close of business on October 30, 2000. All share
and per share data in these financial statements have been restated to reflect
the stock split.
In September 2000, CDI completed a Secondary Stock Offering with Coflexip
selling its 7.4 million shares of common stock at $26.31 per share. The
over-allotment option was exercised resulting in the Company issuing 609,936
shares of common stock and receiving net proceeds of $14.8 million, and the
Chief Executive Officer, selling 500,000 shares receiving net proceeds of $12.1
million.
60
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. BUSINESS SEGMENT INFORMATION (IN THOUSANDS)
The following summarizes certain financial data by business segment:
YEAR ENDED DECEMBER 31,
------------------------------
2002 2001 2000
-------- -------- --------
Revenues --
Subsea and salvage................................. $239,916 $163,740 $110,217
Oil and gas production............................. 62,789 63,401 70,797
-------- -------- --------
Total......................................... $302,705 $227,141 $181,014
======== ======== ========
Income from operations --
Subsea and salvage................................. $ 742 $ 21,705 $ 2,368
Oil and gas production............................. 20,267 23,881 32,201
-------- -------- --------
Total......................................... $ 21,009 $ 45,586 $ 34,569
======== ======== ========
Net interest (income) expense and other --
Subsea and salvage................................. $ 1,359 $ 739 $ (63)
Oil and gas production............................. 609 551 617
-------- -------- --------
Total......................................... $ 1,968 $ 1,290 $ 554
======== ======== ========
Provision for income taxes --
Subsea and salvage................................. $ (793) $ 7,145 $ 436
Oil and gas production............................. 7,457 8,359 11,119
-------- -------- --------
Total........................................... $ 6,664 $ 15,504 $ 11,555
======== ======== ========
Identifiable assets --
Subsea and salvage................................. $642,579 $457,259 $301,416
Oil and gas production............................. 224,453 37,037 46,072
-------- -------- --------
Total......................................... $867,032 $494,296 $347,488
======== ======== ========
Capital expenditures --
Subsea and salvage................................. $ 66,297 $131,062 $ 82,697
Oil and gas production............................. 95,469 20,199 12,427
-------- -------- --------
Total......................................... $161,766 $151,261 $ 95,124
======== ======== ========
Depreciation and amortization --
Subsea and salvage................................. $ 27,220 $ 14,586 $ 11,621
Oil and gas production............................. 17,535 19,947 19,109
-------- -------- --------
Total......................................... $ 44,755 $ 34,533 $ 30,730
======== ======== ========
During the year ended December 31, 2002, the Company derived $27.1 million
of its revenues from the U.K. sector utilizing $91.7 million of its total assets
in this region. Additionally, $66.1 million of revenues were derived from the
Latin America sector during the year ended December 31, 2002. The majority of
the remaining revenues were generated in the U.S. Gulf of Mexico.
61
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
15. 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.
AS OF DECEMBER 31,
------------------------------
2002 2001 2000
-------- -------- --------
Gunnison capitalized costs........................... $ 63,294 $ 10,177 $ --
Proved developed properties being amortized.......... 180,256 72,157 60,679
Less -- Accumulated depletion, depreciation and
amortization....................................... (71,151) (54,482) (35,835)
-------- -------- --------
Net capitalized costs........................... $172,399 $ 27,852 $ 24,844
======== ======== ========
Included in capitalized costs proved developed properties being amortized
is the Company's estimate of its proportionate share of decommissioning
liabilities assumed relating to these properties which are also reflected as
decommissioning liabilities in the accompanying consolidated balance sheets.
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
The following table reflects the costs incurred in oil and gas property
acquisition and development activities during the years indicated:
YEAR ENDED DECEMBER 31,
----------------------------
2002 2001 2000
-------- ------- -------
Proved property acquisition costs...................... $ 94,034 $ 4,350 $ 7,635
Development costs...................................... 67,241 18,247 8,160
-------- ------- -------
Total costs incurred................................. $161,275 $22,597 $15,795
======== ======= =======
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
YEAR ENDED DECEMBER 31,
---------------------------
2002 2001 2000
------- ------- -------
Revenues................................................ $62,789 $63,401 $70,797
Production (lifting) costs.............................. 19,153 13,236 12,432
Depreciation, depletion and amortization................ 17,535 19,947 19,109
------- ------- -------
Pretax income from producing activities................. 26,101 30,218 39,256
Income tax expenses..................................... 7,457 8,359 11,119
------- ------- -------
Results of oil and gas producing activities............. $18,644 $21,859 $28,137
======= ======= =======
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,
2002, excluding Gunnison, have been reviewed by Miller and Lents,
62
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Ltd., independent petroleum engineers. Since the Company does not own a license
to the geophysical data, reserves attributable to Gunnison (which total 47% of
the proved reserves as of December 31, 2002) have been determined based on
information provided by the operator. These reserve estimates were reviewed by
our engineers, including an assessment of the operator's assumptions and their
engineering, geologic and evaluation principles and techniques. All of the
Company's reserves are located in the United States. Proved reserves cannot 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, 2000, -0- Bbls of oil and -0- Mcf of gas of the
Company's proven reserves were undeveloped. As of December 31, 2001, 6,829,000
Bbls of oil and 35,525,000 Mcf of gas were undeveloped, all of which is
attributable to Gunnison. As of December 31, 2002 6,375,000 Bbls of oil and
51,807,000 Mcf of gas were undeveloped, 82% of which is attributable to
Gunnison.
OIL GAS
RESERVE QUANTITY INFORMATION (MBBLS) (MMCF)
---------------------------- ------- -------
Total proved reserves at December 31, 1999.................. 1,702 25,381
Revisions of previous estimates........................... 24 3,024
Production................................................ (739) (14,959)
Purchases of reserves in place............................ 99 9,416
Sales of reserves in place................................ (5) (1,151)
------ -------
Total proved reserves at December 31, 2000.................. 1,081 21,711
------ -------
Revision of previous estimates............................ 623 4,479
Production................................................ (743) (9,473)
Purchases of reserves in place............................ 53 1,644
Sales of reserves in place................................ -- (22)
Extensions and discoveries................................ 6,844 35,597
------ -------
Total proved reserves at December 31, 2001.................. 7,858 53,936
Revision of previous estimates............................ (1,442) 11,049
Production................................................ (922) (11,062)
Purchases of reserves in place............................ 6,543 31,302
Sales of reserves in place................................ -- --
Extensions and discoveries................................ -- --
------ -------
Total proved reserves at December 31, 2002.................. 12,037 85,225
====== =======
63
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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:
2002 2001 2000
--------- --------- --------
Future cash inflows................................ $ 693,023 $ 261,613 $219,620
Future costs --
Production.................................... (129,375) (46,031) (42,608)
Development and abandonment................... (176,094) (147,885) (27,690)
--------- --------- --------
Future net cash flows before income taxes.......... 387,554 67,697 149,322
Future income taxes................................ (106,258) (24,223) (57,018)
--------- --------- --------
Future net cash flows.............................. 281,296 43,474 92,304
Discount at 10% annual rate........................ (69,569) (22,029) (14,591)
--------- --------- --------
Standardized measure of discounted future net cash
flows............................................ $ 211,727 $ 21,445 $ 77,713
========= ========= ========
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:
2002 2001 2000
-------- ------- --------
Standardized measure, beginning of year............... $ 21,445 $77,713 $ 22,843
Sales, net of production costs........................ (43,729) (50,165) (57,720)
Net change in prices, net of production costs......... 69,085 (68,811) 87,427
Changes in future development costs................... 28,958 (2,421) (3,695)
Development costs incurred............................ 67,241 18,247 8,160
Accretion of discount................................. 6,390 3,013 3,785
Net change in income taxes............................ (62,166) 30,192 (32,996)
Purchases of reserves in place........................ 124,322 433 48,229
Extensions and discoveries............................ -- 16,612 --
Sales of reserves in place............................ -- 20 2,021
Net change due to revision in quantity estimates...... 899 1,604 20,084
Changes in production rates (timing) and other........ (718) (4,992) (20,425)
-------- ------- --------
Standardized measure, end of year..................... $211,727 $21,445 $ 77,713
======== ======= ========
64
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
16. 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, 2002 (in thousands):
2002 2001 2000
------- ------- -------
Beginning balance....................................... $ 4,262 $ 1,770 $ 1,789
Additions............................................... 12,008 6,875 4,535
Deductions.............................................. (9,114) (4,383) (4,554)
------- ------- -------
Ending balance.......................................... $ 7,156 $ 4,262 $ 1,770
======= ======= =======
See Note 2 for a detailed discussion regarding the Company's accounting
policy on the Revenue Allowance on Gross Amounts Billed and Note 11 for a
discussion of a large construction project in 2002.
17. 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 2002 and 2001.
QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Fiscal 2002 Revenues..................... $53,928 $72,305 $84,015 $92,457
Gross profit........................... 11,118 17,185 11,573 13,916
Net income............................. 3,001 7,214 2,952 (790)
Net income per share:
Basic............................... .09 .21 .08 (.02)
Diluted............................. .09 .21 .08 (.02)
Fiscal 2001 Revenues..................... $58,482 $48,786 $51,570 $68,303
Gross profit........................... 22,258 16,914 13,207 14,532
Net income............................. 10,774 7,546 5,244 5,368
Net income per share:
Basic............................... .33 .23 .16 .17
Diluted............................. .33 .23 .16 .16
18. SUBSEQUENT EVENTS
SALE OF CONVERTIBLE PREFERRED STOCK
On January 8, 2003, CDI completed the private placement of $25 million of a
newly designated class of cumulative convertible preferred stock (Series A-1
Cumulative Convertible Preferred Stock, par value $0.01 per share) that is
convertible into 833,334 shares of Cal Dive common stock at $30 per share. The
preferred stock was issued to a private investment firm. The preferred stock
holder has the right to purchase as much as $30 million in additional preferred
stock for a period of two years beginning in July, 2003. The conversion price of
the additional preferred stock will equal 125% of the then prevailing price of
Cal Dive common stock, subject to a minimum conversion price of $30 per common
share.
65
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The preferred stock will have a minimum annual dividend rate of 4%, subject
to adjustment, payable in cash or common shares at Cal Dive's option. After the
second anniversary, the holder may redeem the value of its original investments
in the preferred shares to be settled in common stock or cash at the discretion
of the Company. Under certain conditions, the holder could redeem its investment
prior to the second anniversary.
The proceeds received from the sale of this stock, net of transaction
costs, will be classified outside of shareholders' equity on the balance sheet
below total liabilities. The transaction costs will be accreted through the
statement of operations over two years. Prior to the conversion, shares will be
included in the Company's fully diluted earnings per share under the if
converted method based on the Company's average common share price during the
applicable period.
Subsequent to year-end, the Company filed a registration statement
registering approximately 7.5 million shares of common stock relating to this
transaction, the maximum potential total number of shares of common stock
redeemable under certain circumstances, subject to the Company's ability to
redeem with cash, under the terms of the agreement.
66
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
On June 13, 2002, the Company's Board of Directors, upon the recommendation
of its Audit Committee, dismissed Arthur Andersen LLP and appointed Ernst &
Young LLP to serve as the Company's independent auditors for fiscal year 2002.
Arthur Andersen's reports on Cal Dive's consolidated financial statements
for the two fiscal years ended December 31, 2000 and December 31, 2001 did not
contain an adverse opinion or disclaimer of opinion, nor were they qualified or
modified as to uncertainty, audit scope or accounting principles. Additionally,
during the two fiscal years ended December 31, 2000 and December 31, 2001
through the date of Arthur Andersen's dismissal, there were no disagreements
with Arthur Andersen on any matter of accounting principles or practices,
financial statement disclosure, or auditing scope or procedure which, if not
resolved to Arthur Andersen's satisfaction, would have caused Arthur Andersen to
make reference to the subject matter in connection with its reports on the
Company's consolidated financial statements for such years; and there were no
reportable events, as listed in Item 304(a)(1)(v) of Regulation S-K.
The Company provided Arthur Andersen a copy of the foregoing disclosures
and Arthur Andersen advised the Company by letter dated June 18, 2002, that it
has found no basis for disagreement with such statements.
During the fiscal years ended December 31, 2000 and December 31, 2001
through the date of engagement of Ernst & Young, the Company did not consult
with Ernst & Young with respect to the application of accounting principles to a
specified transaction, either completed or proposed, or the type of audit
opinion that might be rendered on the Company's consolidated financial
statements, or any other matters or reportable events as set forth in Items
304(a)(2)(i) and (ii) of Regulation S-K.
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 2003 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 2003 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 2003 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 2003 Annual
Meeting of Shareholders.
ITEM 14. CONTROLS AND PROCEDURES
As of December 31, 2002, an evaluation was performed under the supervision
and with the participation of the Company's management, including the CEO and
CFO, of the effectiveness of the design and operation
67
of the Company's disclosure controls and procedures. Based on that evaluation,
the Company's management, including the CEO and CFO, concluded that the
Company's disclosure controls and procedures were effective as of December 31,
2002. There have been no significant changes in the Company's internal controls
or in other factors that could significantly affect internal controls subsequent
to December 31, 2002.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(1) Financial Statements
The following financial statements included on pages 34 through 55 in this
Annual Report are for the fiscal year ended December 31, 2002.
Report of Independent Auditors
Report of Independent Public Accountants
Consolidated Balance Sheets as of
December 31, 2002 and 2001.
Consolidated Statements of Operations for
the Years Ended December 31, 2002, 2001
and 2000.
Consolidated Statements of Shareholders'
Equity for the Years Ended December 31,
2002, 2001 and 2000.
Consolidated Statements of Cash Flows for
the Years Ended December 31, 2002, 2001
and 2000.
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.
October 1, 2002 -- Item 5.
November 1, 2002 -- Item 9.
November 13, 2002 -- Form 8-K/A filed to include financial statements of
business acquired and the pro forma financial information required by Item 7 for
the acquisition of oil and gas properties purchased from Shell Oil Company by
ERT, as previously reported on Form 8-K filed on August 30, 2002.
(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:
EXHIBITS
NUMBER DESCRIPTION
-------- -----------
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 registrant with the
Securities and Exchange Commission on May 1, 1997 (Reg. No.
333-26357) (the "Form S-1").
3.2 -- By-Laws of registrant, incorporated by reference to Exhibit
3.2 to the Form S-1.
68
EXHIBITS
NUMBER DESCRIPTION
-------- -----------
3.3 -- Articles of Correction, incorporated by reference to Exhibit
3.3 to the Form S-3 Registration Statement filed by
registrant with the Securities and Exchange Commission on
May 22, 2002 (Reg. No. 333- 87620) (the "Form S-3").
3.4 -- Amendment to the 1997 Amended and Restated Articles of
Incorporation of registrant, incorporated by reference to
Exhibit 3.4 to the Form S-3.
3.5 -- Certificate of Rights and Preferences, incorporated by
reference to Exhibit 3.1 to the Current Report on Form 8-K,
filed by registrant with the Securities and Exchange
Commission on January 22, 2003 (the "Form 8-K").
4.1 -- Second Amended and Restated Loan and Security Agreement by
and among Fleet Capital Corporation, Southwest Bank of
Texas, N.A. and Whitney National Bank, as Lenders, and Cal
Dive International, Inc., Energy Resource Technology, Inc.,
Aquatica, Inc. and Canyon Offshore, Inc., as Borrowers,
dated February 22, 2002, incorporated by reference to
Exhibit 4.1 to the registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 2001, filed by the
registrant with the Securities and Exchange Commission on
March 28, 2002 (the "2001 Form 10-K").
4.2* -- First Amendment to Second Amended and Restated Loan and
Security Agreement by and among Fleet Capital Corporation,
Southwest Bank of Texas, N.A. and Whitney National Bank, as
Lenders, and Cal Dive International, Inc., Energy Resource
Technology, Inc., Aquatica, Inc. and Canyon Offshore, Inc.,
as Borrowers, dated August 9, 2002.
4.3* -- Second Amendment to Second Amended and Restated Loan and
Security Agreement by and among Fleet Capital Corporation,
Southwest Bank of Texas, N.A. and Whitney National Bank, as
Lenders, and Cal Dive International, Inc., Energy Resource
Technology, Inc. and Canyon Offshore, Inc., as Borrowers,
dated August 30, 2002.
4.4 -- Third Amendment to Second Amended and Restated Loan and
Security Agreement by and among Fleet Capital Corporation,
Southwest Bank of Texas, N.A. and Whitney National Bank, as
Lenders, and Cal Dive International, Inc., Energy Resource
Technology, Inc. and Canyon Offshore, Inc., as Borrowers,
dated October 24, 2002, incorporated by reference to Exhibit
4.1 to the Form S-3 Registration Statement filed by the
registrant with the Securities and Exchange Commission on
February 26, 2003 (Reg. 333-103451) (the "2003 Form S-3").
4.5* -- Fourth Amendment to Second Amended and Restated Loan and
Security Agreement by and among Fleet Capital Corporation,
Southwest Bank of Texas, N.A. and Whitney National Bank, as
Lenders, and Cal Dive International, Inc., Energy Resource
Technology, Inc. and Canyon Offshore, Inc., as Borrowers,
dated February 14, 2003.
4.6 -- Participation Agreement among ERT, Cal Dive International,
Inc., Cal Dive/Gunnison Business Trust No. 2001-1 and Bank
One, N.A., et. al., dated as of November 8, 2001,
incorporated by reference to Exhibit 4.2 to the 2001 Form
10-K.
4.7 -- Form of Common Stock certificate, incorporated by reference
to Exhibit 4.1 to the Form S-1.
4.8 -- Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO
Incorporated, Citibank N.A. and Citibank International LLC
dated as of August 16, 2000, incorporated by reference to
Exhibit 4.4 to the 2001 Form 10-K.
4.9* -- Amendment No. 1 to Credit Agreement among Cal Dive I-Title
XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank
International LLC dated as of January 25, 2002.
4.10 -- Amendment No. 2 to Credit Agreement among Cal Dive I-Title
XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank
International LLC dated as of November 15, 2002,
incorporated by reference to Exhibit 4.4 to the 2003 Form
S-3.
4.11 -- First Amended and Restated Agreement dated January 17, 2003,
but effective as of December 31, 2002, by and between Cal
Dive International, Inc. and Fletcher International, Ltd.,
incorporated by reference to Exhibit 10.1 to the Form 8-K.
4.12* -- Amended and Restated Credit Agreement among Cal
Dive/Gunnison Business Trust No. 2001-1, Energy Resource
Technology, Inc., Cal Dive International, Inc., Wilmington
Trust Company, a Delaware banking corporation, the Lenders
party thereto, and Bank One, NA, as Agent, dated July 26,
2002.
69
EXHIBITS
NUMBER DESCRIPTION
-------- -----------
4.13* -- First Amendment to Amended and Restated Credit Agreement
among Cal Dive/Gunnison Business Trust No. 2001-1, Energy
Resource Technology, Inc., Cal Dive International, Inc.,
Wilmington Trust Company, a Delaware banking corporation,
the Lenders party thereto, and Bank One, NA, as Agent, dated
January 7, 2003.
4.14* -- Second Amendment to Amended and Restated Credit Agreement
among Cal Dive/Gunnison Business Trust No. 2001-1, Energy
Resource Technology, Inc., Cal Dive International, Inc.,
Wilmington Trust Company, a Delaware banking corporation,
the Lenders party thereto, and Bank One, NA, as Agent, dated
February 14, 2003.
10.1 -- 1995 Long Term Incentive Plan, as amended, incorporated by
reference to Exhibit 10.3 to the Form S-1.
10.2 -- Employment Agreement between Owen Kratz and Company dated
February 28, 1999, incorporated by reference to Exhibit 10.5
to the registrant's Annual Report on Form 10-K for the
fiscal year ended December 31, 1998, filed by the registrant
with the Securities and Exchange Commission on March 31,
1999 (Reg. 000-22739) (the "1998 Form 10-K").
10.3 -- Employment Agreement between Martin R. Ferron and Company
dated February 28, 1999, incorporated by reference to
Exhibit 10.6 of the 1998 Form 10-K.
10.4 -- Employment Agreement between S. James Nelson and Company
dated February 28, 1999, incorporated by reference to
Exhibit 10.7 of the 1998 Form 10-K.
10.5 -- Employment Agreement between A. Wade Pursell and Company
dated January 1, 2002, incorporated by reference to Exhibit
10.7 of the 2001 Form 10-K.
10.6* -- Employment Agreement between Johnny Edwards and Company
dated October 2, 1995.
21.1 -- Subsidiaries of registrant -- The registrant has seven
subsidiaries: Energy Resource Technology, Inc.; Canyon
Offshore, Inc.; Cal Dive ROV, Inc.; Cal Dive I-Title XI,
Inc.; Cal Dive Offshore, Ltd.; Well Ops (U.K.) Limited; and
Well Ops Inc.
23.1* -- Consent of Ernst & Young LLP.
23.2* -- Consent of Miller & Lents, Ltd.
23.3* -- Consent of Ernst & Young LLP.
99.1* -- Certification of Periodic Report by Chief Executive Officer
99.2* -- Certification of Periodic Report by Chief Financial Officer
---------------
* Filed herewith.
70
SIGNATURES
Pursuant to the requirements of section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned. thereunto duly authorized.
CAL DIVE INTERNATIONAL, INC.
By: /s/ A. WADE PURSELL
------------------------------------
A. Wade Pursell
Senior Vice President,
Chief Financial Officer
April 8, 2003
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.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ OWEN KRATZ Chairman, Chief Executive Officer April 8, 2003
------------------------------------------------ and Director
Owen Kratz (principal executive officer)
/s/ MARTIN R. FERRON President, Chief Operating Officer April 8, 2003
------------------------------------------------ and Director
Martin R. Ferron
/s/ S. JAMES NELSON Vice Chairman and Director April 8, 2003
------------------------------------------------
S. James Nelson
/s/ A. WADE PURSELL Senior Vice President April 8, 2003
------------------------------------------------ and Chief Financial Officer
A. Wade Pursell (principal financial and
accounting officer)
/s/ GORDON F. AHALT Director April 8, 2003
------------------------------------------------
Gordon F. Ahalt
/s/ BERNARD J. DUROC-DANNER Director April 8, 2003
------------------------------------------------
Bernard J. Duroc-Danner
/s/ WILLIAM L. TRANSIER Director April 8, 2003
------------------------------------------------
William L. Transier
/s/ JOHN V. LOVOI Director April 8, 2003
------------------------------------------------
John V. Lovoi
/s/ ANTHONY TRIPODO Director April 8, 2003
------------------------------------------------
Anthony Tripodo
71
CERTIFICATIONS
I, Owen Kratz, the Principal Executive Officer of Cal Dive International,
Inc., certify that:
1. I have reviewed this annual report on Form 10-K/A of Cal Dive
International, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: April 8, 2003
/s/ OWEN KRATZ
--------------------------------------
Owen Kratz
Chairman and
Chief Executive Officer
72
I, A. Wade Pursell, the Principal Financial Officer of Cal Dive
International, Inc., certify that:
1. I have reviewed this annual report on Form 10-K/A of Cal Dive
International, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: April 8, 2003
/s/ A. WADE PURSELL
--------------------------------------
A. Wade Pursell
Senior Vice President and
Chief Financial Officer
73
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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 registrant with the
Securities and Exchange Commission on May 1, 1997 (Reg. No.
333-26357) (the "Form S-1").
3.2 -- By-Laws of registrant, incorporated by reference to Exhibit
3.2 to the Form S-1.
3.3 -- Articles of Correction, incorporated by reference to Exhibit
3.3 to the Form S-3 Registration Statement filed by
registrant with the Securities and Exchange Commission on
May 22, 2002 (Reg. No. 333- 87620) (the "Form S-3").
3.4 -- Amendment to the 1997 Amended and Restated Articles of
Incorporation of registrant, incorporated by reference to
Exhibit 3.4 to the Form S-3.
3.5 -- Certificate of Rights and Preferences, incorporated by
reference to Exhibit 3.1 to the Current Report on Form 8-K,
filed by registrant with the Securities and Exchange
Commission on January 22, 2003 (the "Form 8-K").
4.1 -- Second Amended and Restated Loan and Security Agreement by
and among Fleet Capital Corporation, Southwest Bank of
Texas, N.A. and Whitney National Bank, as Lenders, and Cal
Dive International, Inc., Energy Resource Technology, Inc.,
Aquatica, Inc. and Canyon Offshore, Inc., as Borrowers,
dated February 22, 2002, incorporated by reference to
Exhibit 4.1 to the registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 2001, filed by the
registrant with the Securities and Exchange Commission on
March 28, 2002 (the "2001 Form 10-K").
4.2* -- First Amendment to Second Amended and Restated Loan and
Security Agreement by and among Fleet Capital Corporation,
Southwest Bank of Texas, N.A. and Whitney National Bank, as
Lenders, and Cal Dive International, Inc., Energy Resource
Technology, Inc., Aquatica, Inc. and Canyon Offshore, Inc.,
as Borrowers, dated August 9, 2002.
4.3* -- Second Amendment to Second Amended and Restated Loan and
Security Agreement by and among Fleet Capital Corporation,
Southwest Bank of Texas, N.A. and Whitney National Bank, as
Lenders, and Cal Dive International, Inc., Energy Resource
Technology, Inc. and Canyon Offshore, Inc., as Borrowers,
dated August 30, 2002.
4.4 -- Third Amendment to Second Amended and Restated Loan and
Security Agreement by and among Fleet Capital Corporation,
Southwest Bank of Texas, N.A. and Whitney National Bank, as
Lenders, and Cal Dive International, Inc., Energy Resource
Technology, Inc. and Canyon Offshore, Inc., as Borrowers,
dated October 24, 2002, incorporated by reference to Exhibit
4.1 to the Form S-3 Registration Statement filed by the
registrant with the Securities and Exchange Commission on
February 26, 2003 (Reg. 333-103451) (the "2003 Form S-3").
4.5* -- Fourth Amendment to Second Amended and Restated Loan and
Security Agreement by and among Fleet Capital Corporation,
Southwest Bank of Texas, N.A. and Whitney National Bank, as
Lenders, and Cal Dive International, Inc., Energy Resource
Technology, Inc. and Canyon Offshore, Inc., as Borrowers,
dated February 14, 2003.
4.6 -- Participation Agreement among ERT, Cal Dive International,
Inc., Cal Dive/Gunnison Business Trust No. 2001-1 and Bank
One, N.A., et. al., dated as of November 8, 2001,
incorporated by reference to Exhibit 4.2 to the 2001 Form
10-K.
4.7 -- Form of Common Stock certificate, incorporated by reference
to Exhibit 4.1 to the Form S-1.
4.8 -- Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO
Incorporated, Citibank N.A. and Citibank International LLC
dated as of August 16, 2000, incorporated by reference to
Exhibit 4.4 to the 2001 Form 10-K.
4.9* -- Amendment No. 1 to Credit Agreement among Cal Dive I-Title
XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank
International LLC dated as of January 25, 2002.
4.10 -- Amendment No. 2 to Credit Agreement among Cal Dive I-Title
XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank
International LLC dated as of November 15, 2002,
incorporated by reference to Exhibit 4.4 to the 2003 Form
S-3.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.11 -- First Amended and Restated Agreement dated January 17, 2003,
but effective as of December 31, 2002, made by and between
Cal Dive International, Inc. and Fletcher International,
Ltd., incorporated by reference to Exhibit 10.1 to the Form
8-K.
4.12* -- Amended and Restated Credit Agreement among Cal
Dive/Gunnison Business Trust No. 2001-1, Energy Resource
Technology, Inc., Cal Dive International, Inc., Wilmington
Trust Company, a Delaware banking corporation, the Lenders
party thereto, and Bank One, NA, as Agent, dated July 26,
2002.
4.13* -- First Amendment to Amended and Restated Credit Agreement
among Cal Dive/Gunnison Business Trust No. 2001-1, Energy
Resource Technology, Inc., Cal Dive International, Inc.,
Wilmington Trust Company, a Delaware banking corporation,
the Lenders party thereto, and Bank One, NA, as Agent, dated
January 7, 2003.
4.14* -- Second Amendment to Amended and Restated Credit Agreement
among Cal Dive/Gunnison Business Trust No. 2001-1, Energy
Resource Technology, Inc., Cal Dive International, Inc.,
Wilmington Trust Company, a Delaware banking corporation,
the Lenders party thereto, and Bank One, NA, as Agent, dated
February 14, 2003.
10.1 -- 1995 Long Term Incentive Plan, as amended, incorporated by
reference to Exhibit 10.3 to the Form S-1.
10.2 -- Employment Agreement between Owen Kratz and Company dated
February 28, 1999, incorporated by reference to Exhibit 10.5
to the registrant's Annual Report on Form 10-K for the
fiscal year ended December 31, 1998, filed by the registrant
with the Securities and Exchange Commission on March 31,
1999 (Reg. 000-22739) (the "1998 Form 10-K").
10.3 -- Employment Agreement between Martin R. Ferron and Company
dated February 28, 1999, incorporated by reference to
Exhibit 10.6 of the 1998 Form 10-K.
10.4 -- Employment Agreement between S. James Nelson and Company
dated February 28, 1999, incorporated by reference to
Exhibit 10.7 of the 1998 Form 10-K.
10.5 -- Employment Agreement between A. Wade Pursell and Company
dated January 1, 2002, incorporated by reference to Exhibit
10.7 of the 2001 Form 10-K.
10.6* -- Employment Agreement between Johnny Edwards and Company
dated October 2, 1995.
21.1 -- Subsidiaries of registrant -- The registrant has seven
subsidiaries: Energy Resource Technology, Inc.; Canyon
Offshore, Inc.; Cal Dive ROV, Inc.; Cal Dive I-Title XI,
Inc.; Cal Dive Offshore, Ltd.; Well Ops (U.K.) Limited; and
Well Ops Inc.
23.1* -- Consent of Ernst & Young LLP.
23.2* -- Consent of Miller & Lents, Ltd.
23.3* -- Consent of Ernst & Young LLP.
99.1* -- Certification of Periodic Report by Chief Executive Officer.
99.2* -- Certification of Periodic Report by Chief Financial Officer.
---------------
* Filed herewith.