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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
[ ] 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 OF ORGANIZATION) IDENTIFICATION NO.)
400 N. SAM HOUSTON PARKWAY E., SUITE 400 77060
HOUSTON, TEXAS (ZIP CODE)
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
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. [ ]
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 19, 1999 was $154,222,684 based on the last reported
sales price of the Common Stock on March 19, 1999, as reported on the
NASDAQ/National Market System.
The number of shares of the registrant's Common Stock outstanding as of March
19, 1999 was 14,633,581.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement for the Annual Meeting of
Shareholders to be held on May 5, 1999 are incorporated by reference into Part
III hereof.
CAL DIVE INTERNATIONAL, INC. ("CDI") INDEX -- FORM 10-K
PART I
Item 1. Business................................................. 1
Item 2. Properties............................................... 16
Item 3. Legal Proceedings........................................ 19
Item 4. Submission of Matters to a Vote of Security Holders...... 19
Unnumbered Executive Officers of Registrant......................... 20
Item
PART II
Item 5. Market for the Registrant's Common Equity and Related
Shareholder Matters...................................... 22
Item 6. Selected Financial Data.................................. 23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................. 23
Results of Operations.................................... 25
Liquidity and Capital Resources.......................... 27
Item 7A. Quantitative and Qualitative Disclosure About Market
Risk................................................. 29
Item 8. Financial Statements and Supplementary Data.............. 29
Independent Auditors' Report.......................... 31
Consolidated Balance Sheets -- December 31, 1998
and 1997.......................................... 32
Consolidated Statements of Operations --
Three Years Ended December 31, 1998............... 33
Consolidated Statements of Shareholders' Equity --
Three Years Ended December 31, 1998............... 34
Consolidated Statements of Cash Flows --
Three Years Ended December 31, 1998............... 35
Notes to Consolidated Financial Statements............... 36
Item 9. Changes In and Disagreements With Accountants on
Accounting and Financial Disclosure............... 48
PART III
Item 10. Directors and Executive Officers of the Registrant....... 48
Item 11. Executive Compensation................................... 48
Item 12. Security Ownership of Certain Beneficial Owners and
Managers................................................ 48
Item 13. Certain Relationships and Related Transactions........... 48
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K................................................ 49
Signatures............................................... 51
(i)
PART I
ITEM 1. BUSINESS
GENERAL
Cal Dive International, Inc. ("CDI" or the "Company") is a leading subsea
contractor providing services from the shallowest to the deepest waters in the
Gulf of Mexico. Over three decades, CDI has developed a reputation for
innovation in underwater construction techniques and equipment. With its
diversified fleet of 11 vessels and access to barges under its alliance with
Horizon Offshore Inc. ("Horizon"), CDI performs services which cover the life of
an offshore natural gas or oil field. Through its subsidiary, Energy Resource
Technology, Inc. ("ERT"),it acquires mature offshore properties to provide
customers a cost effective alternative to the decommissioning process. The
Company's customers include major and independent natural gas and oil producers,
pipeline transmission companies and offshore engineering and construction firms.
In water depths up to 1,000 feet ("OCS"), CDI is a dominant provider of
subsea services which include air and SAT diving in support of marine
construction activities. Each of the Company's 11 vessels perform these
services, six of which support SAT diving. CDI owns a large minority share in
Aquatica, Inc., a new shallow water diving company, which grew significantly in
1998. CDI also has a new service beginning in 1999 which involves a methodology
for shallow water full field development designed to reduce new field cost and
completion time.
Activity in Gulf water depths greater than 1,000 feet (the "Deepwater")
involves technological challenges which have required subsea contractors to
develop new technology. With a fleet of four Deepwater-capable vessels, CDI has
assembled a technically diverse fleet permanently deployed in the Gulf for the
delivery of these subsea solutions. CDI has formed alliances with other offshore
service and equipment providers which enhance its ability to provide full field
and life of field services, including a strategic alliance with Coflexip, a
world leader serving the Deepwater market. CDI is also developing a new
Deepwater construction vessel, the Q4000 and assisting industry groups to
develop new technology to solve challenges of Deepwater projects which can be
deployed from its DP vessels.
OFFSHORE Magazine recently affirmed Cal Dive as the number one player in
the decommissioning market as CDI was responsible for 24% of the structures
removed from the Gulf during the years 1996 through mid-1998. CDI's alliance
with Horizon provides access to expanded derrick and heavy lift salvage
capabilities. ERT acquires, produces and develops mature properties prior to
their decommissioning and as such is one of few companies with the combined
attributes of financial strength, reservoir engineering, operations expertise
and company-owned salvage assets that is acquiring mature properties in the Gulf
of Mexico.
RECENT EVENTS
Excess supplies of crude oil and lower demand internationally drove oil
prices to $11 a barrel by late fall of 1998. At the outset of 1999, the state of
the world's economies and the actions of our customers, who are cutting budgets
and reducing capital expenditures, continues to affect almost all aspects of the
oil and gas industry. While losses from customer inability to pay (bad debt
expenses) have historically been insignificant, the current downturn could also
result in bankruptcy or liquidation of certain of the smaller production
companies that operate in the Gulf. Although CDI believes these pressures may
not be resolved in 1999, it has developed measured responses to these
conditions. For example, CDI has implemented cost reduction and containment
initiatives and expects to continue to do so as conditions dictate. Most of Cal
Dive's employees and management were with the Company when it experienced
cyclical downturns such as those in 1985-6 and 1992. Lessons learned from those
times will be applied. However, it is difficult to forecast the
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full impact of such a severe cyclical downturn. Some opportunities which CDI
plans to pursue in 1999 are described below.
ERT ACQUISITIONS
In 1998, ERT acquired interests in six blocks involving two fields. Early
in 1999, ERT completed three additional acquisitions (including its largest
acquisition to date) by purchasing interests in seventeen blocks involving seven
separate fields. With these acquisitions, ERT as of March 19, 1999 owned
interests in 35 offshore leases including 32 platforms, 22 caissons, and 184
wells which currently produce about 21 MMCFD and 755 BOPD and has accumulated a
significant backlog of CDI decommissioning work. Given recent oil and gas
company down sizing and layoffs, management believes many of its customers are
reassessing the cost of retaining marginal properties and expects ERT will
benefit from this activity.
SHALLOW WATER FULL-FIELD DEVELOPMENT
CDI believes it has assembled a unique new product/service designed to
bring a new field online efficiently and in periods of as little as seventeen
weeks. Working with proven designs that meet or exceed industry standards, Cal
Dive now stocks or has ready access to the necessary production equipment such
as subsea trees, prefabricated facility modules, well controls, and decks to
assist in the rapid assembly of a new field. Currently under contract to SOCO
Offshore, CDI has completed the staging of a subsea tree and production
equipment within the 12 week target and will mobilize the installation spread
upon completion of drilling operations on the host facility. This equipment,
combined with CDI's years of experience and assets which can complete all phases
of the operation should allow clients to minimize contractor interfaces and
accurately assess costs for the life of their field.
HORIZON ALLIANCE
In the fourth quarter of 1998, CDI entered into an Alliance agreement that
provides access to expanded derrick and heavy lift barge capabilities. Under the
agreement, Horizon exclusively contracts Cal Dive for all dive support vessels
and barge diving services. In return, Cal Dive has agreed to utilize Horizon
pipelay and derrick barges exclusively for large diameter pipelay and salvage
lifts beyond current CDI capabilities. In this regard Cal Dive has guaranteed a
certain level of barge activity which it expects to use in conjunction with its
salvage operations. In the fourth quarter of 1998, Cal Dive vessels and divers
were used for over 180 combined days of work in conjunction with Horizon pipelay
operations and for 20 days on salvage work.
Q4000 MSV
The Q4000, a sixth generation multi-service Deepwater completion and
construction support vessel, is now in the final design stages. Much of 1998 was
spent refining the design of this new build vessel to incorporate more unique
features. A technology sharing alliance with R& B Falcon allowed the Company to
utilize the experiences of operating the UNCLE JOHN and the IOLAIR, two
third-generation semi-submersible vessels. CDI is presently in the process of
evaluating final cost estimates from a select group of shipyards with final
evaluations scheduled for mid-year 1999.
DESCRIPTION OF OPERATIONS
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THE INDUSTRY AND CDI
The subsea services industry in the Gulf of Mexico originated in the early
1960s to assist natural gas and oil companies with offshore operations. The
industry has grown significantly since the early 1970s as the domestic oil and
gas industry has increasingly relied upon offshore fields for new production.
Subsea services are required throughout the economic life of an offshore field
and include the following services, among others:
o Exploration. Pre-installation survey; rig positioning and installation
assistance; drilling inspection; subsea equipment maintenance; search
and recovery operations.
o 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.
o Production. Inspection, maintenance and repair of production
structures, risers and pipelines and subsea equipment.
o Decommissioning. Decommissioning and remediation services; plugging and
abandonment services; platform salvage and removal; pipeline
abandonment; site inspections.
Terms defined below are helpful to understanding the services CDI performs in
support of the phases of offshore field development:
4-POINT: Anchors set (two each) from the fore and aft position of the
vessel.
DECOMMISSIONING: The process, supervised by the Minerals Management
Service ("MMS"), of plugging the well, capping and burying the pipelines
serving the field, removing the platform and clearing the site of all
debris.
DIVE SUPPORT VESSEL (DSV): Specially equipped vessel which performs
services and acts as an operational base for divers, ROVs and specialized
equipment.
DYNAMIC POSITIONING (DP): Computer-directed thruster systems, that use
satellite-based positioning combined with other positioning technologies,
to ensure the proper counteraction to wind, current and wave forces
enabling the vessel to maintain its position without the use of anchors.
Two additional DP systems are used to provide the redundancy necessary to
support safe deployment of divers where only a single DP system is
necessary to support ROV equipment
MOONPOOL: An opening in the center of a vessel through which a SAT diving
system or ROV may be deployed, allowing the safest diver or ROV deployment
in adverse weather conditions.
REMOTELY OPERATED VEHICLE (ROV): Robotic vehicles used to complement,
support and increase the efficiency of diving and subsea operations and
for tasks beyond the capability of manned diving operations.
SATURATION (SAT) DIVING: SAT diving, required for work in water depths
greater than 300 feet, involves divers working from special chambers for
extended periods at a pressure equivalent to the depth of the work site.
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SPOT MARKET: Market unique to the Gulf of Mexico characterized by projects
generally short in duration and of a turnkey nature. These projects
require constant rescheduling and the availability or interchangeability
of multiple vessels.
The Company traces its origins to California Divers Inc., which pioneered
the use of mixed gas diving in the early 1960s when oilfield exploration off the
Santa Barbara coast moved to water depths beyond 250 feet. Cal Dive commenced
operations in the Gulf of Mexico in 1975. The Company's growth strategy has
consisted of three basic elements: (i) identifying the niche markets that are
underserviced or where no service exists, (ii) developing the technical
expertise to provide the service and (iii) acquiring assets or seeking alliances
which fill the market gap. As a result, CDI's revenues have increased by a
compound annual growth rate of 60% from $37.5 million in 1995 to $151.9 million
in 1998. Similarly, net income has increased by a compound annual growth rate of
108% from $2.7 million in 1995 to $24.1 million in 1998. A more detailed
description of the Company's business activities is provided below.
SUBSEA SERVICES
The principal activity of CDI's subsea services involves air and
saturation diving in support of pipelay and related marine construction
activities. Saturation diving is required for diving operations in water depths
beyond 300 feet. CDI believes that it is the largest provider of SAT diving
services and operates the largest fleet of SAT diving vessels permanently
deployed in the Gulf. Cal Dive's diversified fleet includes one DP MSV, three DP
DSVs, two four-point moored saturation DSVs, three other DSVs, two work class
ROVs, a DSV Deepwater service barge and a derrick barge. All of CDI's SAT diving
vessels have moonpool systems, which allow safe diver deployment in adverse
weather conditions. The Company expects delivery in 1999 of a replacement for
its smallest DSV, the CAL DIVER IV. The services provided by these vessels both
overlap and are complementary in a number of market segments, enabling the
Company to deploy its vessels to areas of highest utility and margin potential.
In 1998, demand and rates for these services held fairly firm throughout most of
the year due to shortages of diving personnel. Since CDI dominates the
saturation market where divers receive premium pay, personnel shortages did not
curtail its operations.
Ongoing reductions of experienced personnel at CDI's customers have
continued a trend of transferring more responsibility to contractors and
suppliers. Management believes that a key element of CDI's strategy and success
has been its pioneering role in providing turnkey contracting and its ability to
attract and retain experienced industry personnel. The Company's highly
qualified personnel enable it to compete effectively in the Gulf's unique "spot
market" for offshore construction projects and to manage turnkey projects to
satisfy customer needs and achieve CDI's targeted profitability. Because of its
experience with turnkey contracting and the recognized skill of its personnel,
the Company believes it has proven it can capitalize on the demand for
outsourcing additional responsibility to contractors.
In February 1998, CDI purchased a significant minority stake in Aquatica,
a new shallow water diving company formed by Sonny Freeman, the former Chief
Operating Officer of Ceanic Corporation (formerly American Oilfield Divers)
which was purchased in 1998 by Stolt Comex Seaway, Inc. In 1998, Aquatica's
equity contribution to CDI's pre-tax income was over $2.6 million on a $5.0
million investment. Management believes that its investment in Aquatica permits
the Company to benefit from the skills of proven management in this market while
allowing Cal Dive to continue to focus on its Deepwater strategy. Dependent upon
various preconditions, CDI has agreed to lend an additional $5.0 million to
Aquatica and its shareholders have the right to convert their shares into CDI
shares at a prescribed ratio which, among other things, must be accretive to
CDI's earnings per share.
DEEPWATER TECHNOLOGIES
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In 1994, CDI began to assemble a fleet of DP vessels which are required to
deliver subsea services in the Deepwater. The Company's Deepwater fleet consists
of one semisubmersible DP MSV (the UNCLE JOHN), three DP DSV's (the WITCH QUEEN,
the BALMORAL SEA, and the MERLIN), one Deepwater service barge (the SEA
SORCERESS), two 4-point moored saturation DSVs (the CAL DIVER I and the CAL
DIVER II) and two work class ROVs. The Company intends to continue to expand the
capabilities of its diversified fleet through the acquisition of additional
vessels and assets. All of CDI's DP vessels (except the MERLIN) can support SAT
diving on the Outer Continental Shelf ("OCS") as compared to most competitors'
DP vessels which can only support ROV work. CDI's mono-hulled DP vessels provide
a flexible work platform to launch ROVs and support subsea construction in
adverse weather conditions. Likewise, the Company's MSV UNCLE JOHN has
demonstrated the ability to perform certain well completion tasks previously
done by more expensive drilling equipment. These vessels, in combination with
the ROVs, allow CDI to control key assets involved in Deepwater subsea
construction and full field development.
CDI formed its Deepwater Technical Services Group in early 1996 to serve
as the focal point for delivering the varied technological disciplines required
for Deepwater projects. Services provided by this Group include geotechnical
investigation, turnkey field development, installation of umbilicals, controls
and flexible pipe, well servicing, decommissioning, subsea wellhead
installations and pipeline repair systems and riser installation. In 1998, the
Company completed or was awarded 15 Deepwater projects requiring DP vessels.
These projects allowed CDI to perform work numerous times at what management
believes to be record depths. Work by Company's alliance partners described
below are also coordinated through this group.
As part of its strategy in the Deepwater Gulf of Mexico, CDI entered into
a number of strategic alliances, including establishment of a joint venture with
Coflexip in April 1997 to pursue EPIC projects in the Gulf and the Caribbean.
Coflexip, headquartered in Paris, France, is a world leader in the design and
manufacture of flexible pipe and umbilicals and is one of the leading subsea
construction contractors. In 1998, Coflexip had sales of $1.34 billion and total
assets of $1.32 billion at year-end. The Coflexip joint venture has not produced
any revenue to date but the Company expects that EPIC projects may develop along
with increased Deepwater activity by 2001. However, Coflexip did make two of
their DP vessels available to the Company which added $8 million to 1998
revenues.
CDI's other alliances, intended to enhance its ability to offer a complete
range of subsea full field development services, are described below:
ALLIANCE DESCRIPTION 1997/1998 CONTRIBUTIONS
Schlumberger, Ltd...... Alliance Agreement whereby CDI Downhole equipment played
provides DP vessels and related major roles in several complex
operating services for well well intervention jobs
servicing and testing
Horizon Offshore, Inc.. Alliance Agreement whereby CDI Vessel, diver and pipelay work
provides all dive support vessels all occurred in third and fourth quarter
and barge diving services. CDI 1998
uses Horizon barges for platform
abandonment and pipelay work
5
Fugro-McClelland....... Performance Contract whereby CDI Coring work identified the
Marine Geoscience, Inc. provides operating services for underwater aquifers causing
geoscience services and coring work Deepwater sand flow
Shell Offshore Inc..... Performance Contract whereby CDI Contracted to provide well
provides vessels and related intervention services over a
operating services for subsea well two-year period
intervention and the development of
J-lay procedures
TOPS................... Preferred Provider Agreement Marine construction services
whereby CDI provides marine
contracting services in a full field
development setting to TOPS in the
Deepwater Gulf of Mexico
Reading & Bates........ Alliance Agreement to cooperate on Construction Estimates in process
Development Co the design of a new build MSV for the Q4000
Canyon................ Alliance Agreement where Canyon Marine construction services
supports CDI's ROV operations and
provides ROV personnel/equipment
Ambar................. Alliance Agreement to develop a Development testing in process
Deepwater offshore pipeline cleaning
system
CDI is also involved in a number of efforts to provide for technical
challenges as the industry moves into the Deepwater. In 1998, the design of
CDI's new build, the Q4000, was refined to include new Deepwater features. CDI
is also involved in seeking solutions to other unique Deepwater issues. In 1998
a number of wells were lost to shallow sand flow, a geological phenomenon unique
to the Deepwater Gulf. CDI is involved with DeepStar, the consortium of 22 oil
companies having significant interest in the Deepwater Gulf in designing a
hammer to drive a 36" caisson 2,000 feet into the ocean floor in order to
provide a drilling conduit through the aquifer. A second major issue is that of
hydrates, the waxy substance which impedes pipeline flow as the high paraffin
content of the oil interacts with the extreme cold of the Deepwater. This
situation presently limits offsets and step out wells as flowline insulation
costs escalate to non-economic levels. CDI and alliance partner Ambar are
developing an extended reach method of cleaning hydrates from the pipeline. In
each case CDI's goal is to develop new Deepwater products which can be deployed
from our fleet of DP vessels.
ABANDONMENT SOLUTIONS
The Company has established a leading position in the decommissioning of
facilities in the shallow water Gulf of Mexico. According to OFFSHORE MAGAZINE,
CDI performed 24% of all structure removal projects in the Gulf from January 1,
1996 through June 30, 1998. The Company expects the demand for decommissioning
services to increase due to the significant number of platforms that must be
removed in accordance with government regulations. Over 75% of the 4,200
platforms in the Gulf of Mexico are over ten years old and there are
approximately 20,000 wells that must ultimately be plugged and abandoned. Since
1989, Cal Dive
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has undertaken a wide variety of decommissioning assignments, most on a turnkey
basis.
When the structure to be removed exceeds the capacity of CDI's equipment,
the Company can utilize its 1998 alliance with Horizon. Horizon operates three
derrick barges, the PACIFIC HORIZON, ATLANTIC HORIZON and PHOENIX HORIZON, that
have lift capacities ranging up to 800 tons. As a result, CDI should no longer
have to subcontract those projects where the lift exceeds the 200-ton capacity
of the CAL DIVE BARGE-I.
CDI formed ERT in 1992 to exploit a market opportunity to provide a more
efficient solution to the abandonment of offshore properties, to expand Cal
Dive's off season salvage and decommissioning activity and to support full field
development projects. CDI has assembled and recently expanded its team of
personnel experienced in geology, geophysics, reservoir, drilling and production
engineering, facilities management and lease operations to allow ERT to maximize
production at these properties until they are decommissioned. Mature properties
are generally those properties where decommissioning costs are significant
relative to the value of remaining natural gas and oil reserves. CDI seeks to
acquire properties that it can operate to enhance remaining production, control
operating expenses and manage the cost and timing of the decommissioning.
Management believes that CDI is one of the few companies which combines
financial strength, reservoir engineering, operations expertise and the
availability of company-owned salvage assets that is acquiring mature properties
in the Gulf of Mexico. These attributes result in significant strategic and cost
advantages. Since acquiring its initial property in late 1992, the Company has
increased estimated proved reserves to approximately 30.4 Bcfe of natural gas
and oil at March 19, 1999.
CUSTOMERS
The Company's customers include major and independent natural gas and oil
producers, pipeline transmission companies and offshore engineering and
construction firms. The level of construction services required by any
particular customer depends on the size of that customer's capital expenditure
budget devoted to construction plans in a particular year. Consequently,
customers that account for a significant portion of contract revenues in one
fiscal year may represent an immaterial portion of contract revenues in
subsequent fiscal years. The Company estimates that in 1998 it provided subsea
services to approximately 100 customers. Chevron USA, Inc. accounted for 11% of
consolidated revenues in 1998. J. Ray McDermott, S.A. accounted for 19% and 24%
of consolidated revenues in the years 1997 and 1996, respectively. In addition,
Shell Oil Co. accounted for 11% of consolidated revenues in 1997. The Company's
projects are typically of short duration and are generally awarded shortly
before mobilization. Accordingly, backlog is not a meaningful indicator of
future activities.
COMPETITION
The subsea services industry is highly competitive. Competition has
historically been based on factors such as the location and type of equipment
available, the ability to deploy such equipment, the safety and quality of
service in recent years and price. While price is a factor, the ability to
acquire specialized vessels, to attract and retain skilled personnel, and to
demonstrate a good safety record are important competitive factors. CDI's
competitors in the shallower waters of the Gulf include Stolt Comex Seaway, Inc.
(formerly Ceanic Corporation), Torch, Inc., Global Industries Ltd. and
Oceaneering International, Inc. as well as a number of smaller companies, some
of which only operate a single vessel, that often compete solely on price. For
Deepwater projects, Cal Dive's principal U.S. based competitors include
Oceaneering International, Inc., Global Industries, Ltd. and Stolt Comex Seaway,
Ltd. Other large foreign based subsea contractors, including, DSND, ASA and
Rockwater, Ltd., may perform services in the Gulf. Of those competitors,
Oceaneering has recently introduced the OCEAN INTERVENTION I and has announced
plans to have a second vessel (OCEAN INTERVENTION II) in the marketplace late in
1999. SCS now has the CONDOR in the Gulf with the PUMA a possible arrival later
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in the year. CDI also encounters significant competition for the acquisition of
producing natural gas and oil properties. The Company's ability to acquire
additional properties also depends upon its ability to evaluate and select
suitable properties and to consummate transactions in a highly competitive
environment. Many of the Company's competitors are well-established companies
with substantially larger operating staffs and greater capital resources than
CDI which, in many instances, have been engaged in the energy business for a
much longer time than CDI.
TRAINING, SAFETY AND QUALITY ASSURANCE
CDI maintains a stringent safety and quality assurance program. In 1994,
the Company devised and instituted a comprehensive revision to its safety
program which emphasizes team building by assembling a core group of personnel
specifically for each vessel to promote offshore efficiency and safety.
Assembling core groups of personnel specifically assigned to each vessel has
also reduced recorded incidents. As a result, management believes that CDI's
safety programs are among the best in the industry.
GOVERNMENT REGULATION
Many aspects of the offshore marine construction industry are subject to
extensive governmental regulation. The Company is subject to the jurisdiction of
the United States Coast Guard ("USCG"), the Environmental Protection Agency,
Minerals Management Service ("MMS") and the U.S. Customs Service ("USCS") as
well as private industry organizations such as the American Bureau of Shipping
("ABS").
CDI supports and voluntarily complies with the Association of American
Diving Contractor Standards. The USCG sets safety standards and is authorized to
investigate vessel and diving accidents and recommend improved safety standards,
and the USCS is authorized to inspect vessels at will. CDI is required by
various governmental and quasi-governmental agencies to obtain certain permits,
licenses and certificates with respect to its operations. The Company believes
that it has obtained or can obtain all permits, licenses and certificates
necessary for the conduct of its business.
In addition, CDI depends on the demand for its services from the oil and
gas industry and, therefore, the Company's business is affected by laws and
regulations, as well as changing taxes and policies relating to the oil and gas
industry generally. In particular, the development and operation of natural gas
and oil properties located on the OCS of the United States is regulated
primarily by the MMS.
The MMS requires lessees of OCS properties to post bonds in connection
with the plugging and abandonment of wells located offshore and the removal of
all production facilities. Operators in the OCS waters of the Gulf of Mexico are
currently required to post an area wide bond of $3.0 million or $500,000 per
producing lease. The Company currently has bonded its 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 the Company's operations could have a material adverse effect on
the Company's financial condition and results of operations.
The Company acquires production rights to offshore mature oil and gas
properties under federal oil and gas leases, which the MMS administers. These
leases contain relatively standardized terms and require compliance with
detailed MMS regulations and orders pursuant to the Outer Continental Shelf
Lands Act ("OCSLA") (which are subject to change by the MMS). The MMS has
promulgated regulations requiring offshore production facilities located on the
OCS to meet stringent engineering and construction specifications. These latter
regulations were withdrawn pending further discussions among interested federal
agencies. The MMS also has issued regulations restricting the flaring or venting
of natural gas and prohibiting the burning of liquid hydrocarbons without prior
authorization. Similarly, the MMS has promulgated other regulations
8
governing the plugging and abandonment of wells located offshore and the removal
of all production facilities. Finally, under certain circumstances, the MMS may
require any operations on federal leases to be suspended or terminated, and the
MMS has recently proposed, but not yet enacted, regulations that would allow it
to expel unsafe operators from existing OCS platforms and bar them from
obtaining future leases. Any such suspension or termination or ban could
materially and adversely affect the Company's financial condition and
operations.
The MMS has also issued a notice of proposed rulemaking in which it
proposes to amend its regulations governing the calculation of royalties and the
valuation of crude oil produced from federal leases. The proposed rule would
modify 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, establish a new MMS form for
collecting value differential data, and amend the valuation procedure for the
sale of federal royalty oil. The Company cannot predict at this stage of the
rulemaking proceeding how it might be affected by this amendment to the MMS'
regulations. In addition, the MMS recently issued a final rule amending its
regulations regarding costs for gas transportation which are deductible for
royalty valuation purposes when gas is sold offlease. Among other matters, for
purposes of computing royalty owed, the rule disallows as deductions certain
costs, such as aggregator/marketer fees and transportation imbalance charges and
associated penalties.
Historically, the transportation and sale for resale of natural gas in
interstate commerce has been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the
past, the federal government has regulated the prices at which gas and oil could
be sold. While sales by producers of natural gas, and all sales of crude oil,
condensate, and natural gas liquids can currently be made at uncontrolled market
prices, Congress could reenact price controls in the future. Deregulation of
wellhead sales in the natural gas industry began with the enactment of the NGPA.
In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended
the NGPA to remove both price and non-price controls from natural gas sold in
"first sales" no later than January 1, 1993.
Sales of natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation remain
subject to extensive federal and state regulation. Several major regulatory
changes have been implemented by Congress and the FERC from 1985 to the present
that affect the economics of natural gas production, transportation and sales.
In addition, the FERC continues to promulgate revisions to various aspects of
the rules and regulations affecting those segments of the natural gas industry,
most notably interstate natural gas transmission companies that remain subject
to the FERC's jurisdiction. These initiatives may also affect the intrastate
transportation of gas under certain circumstances. The stated purpose of many of
these regulatory changes is to promote competition among the various sectors of
the natural gas industry. The ultimate impact of the complex rules and
regulations issued by the FERC since 1985 cannot be predicted. In addition, many
aspects of these regulatory developments have not become final but are still
pending judicial and FERC final decisions.
The Company cannot predict what further action the FERC will take on these
matters, however, the Company does not believe that it will be affected by any
action taken materially differently than other companies with which it competes.
Additional proposals and proceedings before various federal and state
regulatory agencies and the courts could affect the oil and gas industry. The
Company cannot predict when or whether any such proposals may become effective.
In the past, the natural gas industry has been heavily regulated. There is no
assurance that the regulatory approach currently pursued by the FERC will
continue indefinitely. Notwithstanding the foregoing, the Company does not
anticipate that compliance with existing federal, state and local laws, rules,
9
and regulations will have a material effect upon the capital expenditures,
earnings, or competitive position of the Company.
The Company has assessed what computer software will require modification
or replacement so that its computer systems will properly utilize dates beyond
December 31, 1999. The Company has purchased, and has implemented, a new project
management accounting system which is Year 2000 compliant. This system, which
fully integrates all of its modules, provides project managers and accounting
personnel with up-to-date information enabling them to better control jobs in
addition to providing benefits in inventory control and planned vessel
maintenance. CDI's vessel computer DP systems are partially dependent on
government satellites and the government has not yet confirmed that they have
solved Year 2000 data problems. If necessary, the vessels could operate for
sometime safely on redundant systems other than satellite information.
Accordingly, the Company believes that the Year 2000 issue will be resolved in a
timely manner and presently does not believe that the cost to become Year 2000
compliant will have a material adverse effect on the Company's consolidated
financial statements. The foregoing statements are intended to be and are hereby
designated "Year 2000 Readiness Disclosure" within the meaning of the Year 2000
Information Readiness and Disclosure Act.
ENVIRONMENTAL REGULATIONS
The Company's operations are subject to a variety of federal, state and
local laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. Numerous
governmental departments issue rules and regulations to implement and enforce
such laws that are often complex and costly to comply with, and that carry
substantial administrative, civil and possibly criminal penalties for failure to
comply. Aside from possible liability for damages and costs associated with
releases of hazardous materials including oil into the environment, such laws
and regulations may impose liability on the Company for the conduct of or
conditions caused by others, or by acts of the Company that were in compliance
with all applicable laws at the time such acts were performed.
The Oil Pollution Act of 1990, as amended ("OPA"), imposes a variety of
requirements on "responsible parties" related to the prevention of oil spills
and liability for damages resulting from such spills in waters of the United
States. A "responsible party" includes the owner or operator of an onshore
facility, vessel or pipeline, or the lessee or permittee of the area in which an
offshore facility is located. OPA imposes liability on each responsible party
for oil spill removal costs and for other public and private damages from oil
spills. Failure to comply with OPA may result in the assessment of civil and
criminal penalties. OPA establishes liability limits of up to $350.0 million for
onshore facilities, all removal costs plus up to $75.0 million for offshore
facilities, and the greater of $500,000 or $600 per gross ton for vessels other
than tank vessels. The liability limits are not applicable, however, if the
spill is caused by gross negligence or willful misconduct, if the spill resulted
from violation of a federal safety, construction, or operating regulation, or if
a party fails to report a spill or fails to cooperate fully in the cleanup. Few
defenses exist to the liability imposed under OPA. Management of the Company is
currently unaware of any oil spills for which the Company has been designated as
a responsible party under OPA that will have a material adverse impact on the
Company or its operations.
OPA also imposes ongoing requirements on a responsible party including
preparation of an oil spill contingency plan and proof of financial
responsibility to cover a majority of the costs in a potential spill. The
Company believes it has appropriate spill contingency plans in place. Vessels
subject to OPA other than tank vessels are subject to financial responsibility
limits of the greater of $500,000 or $600 per gross ton, while offshore
facilities are subject to financial responsibility limits of not less than $35.0
million, with that limit potentially increasing up to $150.0 million if a formal
risk assessment indicates that a greater amount is required. The MMS has
promulgated regulations implementing these financial responsibility requirements
for
10
covered offshore facilities. Under the MMS regulations, the amount of financial
responsibility required for an offshore facility is increased above the minimum
amounts of the "worst case" oil spill volume calculated for the facility exceeds
certain limits established in the regulations. The Company believes that it
currently has established adequate proof of financial responsibility for its
vessels and onshore and offshore facilities and that it satisfies the MMS
requirements for financial responsibility under OPA and the proposed
regulations.
OPA also requires owners and operators of vessels over 300 gross tons to
provide the USCG with evidence of financial responsibility to cover the cost of
cleaning up oil spills from such vessels. The Company currently owns and
operates five vessels over 300 gross tons. Satisfactory evidence of financial
responsibility has been provided to the USCG for all of the Company's vessels.
The Clean Water Act imposes strict controls on the discharge of pollutants
into the navigable waters of the U.S., and imposes potential liability for the
costs of remediating releases of petroleum and other substances. The Clean Water
Act provides for civil, criminal and administrative penalties for any
unauthorized discharge of oil and other hazardous substances and imposes
substantial potential liability for the costs of removal, remediation and
damages. Many states have laws which are analogous to the Clean Water Act and
also require remediation of releases of petroleum and other hazardous substances
in state waters. The Company's vessels routinely transport diesel fuel to
offshore rigs and platforms, and also carry diesel fuel for their own use. The
Company's 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 the Company have
facility and vessel response plans to deal with potential spills of oil or its
derivatives.
OCSLA provides the federal government with broad discretion in regulating
the release of offshore resources of natural gas and oil production as well as
regulating safety and environmental protection applicable to lessees and
permittees operating in the 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 the Company's
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 the Company's financial condition and the results of
operations. As of this date, the Company believes it is not the subject of any
civil or criminal enforcement actions under OCSLA.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA") contains provisions dealing with remediation of releases of hazardous
substances into the environment and imposes liability without regard to fault or
the legality of the original conduct, on certain classes of persons including
owners and operators of contaminated sites where the release occurred and those
companies who transport, dispose of or who arrange for disposal of hazardous
substances released at the sites. Under CERCLA, such persons may be subject to
joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, for damages to natural
resources and for the costs of certain health studies, and it is not uncommon
for third parties to file claims for personal injury and property damage
allegedly caused by the release of hazardous substances. Although the Company
handles hazardous substances in the ordinary course of business, the Company is
not aware of any hazardous substance contamination for which it may be liable.
Management believes the Company is in compliance in all material respects
with all applicable environmental laws and regulations to which it is subject.
The Company does not anticipate that compliance with existing environmental laws
and regulations will have a material effect upon the capital expenditures,
earnings or competitive position of the Company. However, changes in the
environmental laws and regulations,
11
or claims for damages to persons, property, natural resources or the
environment, could result in substantial costs and liabilities to the Company
and thus there can be no assurance that the Company will not incur significant
environmental compliance costs in the future.
EMPLOYEES
CDI relies on the high quality of its workforce and has successfully
hired, trained, and retained skilled managers and divers. As of December 31,
1998 the Company had 478 employees, 127 of which were salaried. As of that
date the Company also utilized approximately 105 non-US citizens to crew its
foreign flag vessels under a crewing contract with C-MAR Services (UK), Ltd. of
Aberdeen, Scotland. None of the Company's employees belong to a union or are
employed pursuant to any collective bargaining agreement or any similar
arrangement. Management believes that the Company's relationship with its
employees and foreign crew members is good.
Of the Company's employees, approximately 225 persons own shares of Common
Stock and 43 other employees hold options to acquire Common Stock under the
Company's 1995 Long Term Incentive Plan, as amended.
FACTORS INFLUENCING FUTURE RESULTS AND ACCURACY OF
FORWARD LOOKING INFORMATION
Shareholders should carefully consider the following risk factors in
addition to the other information contained in this Annual Report. This Annual
Report on Form 10-K includes certain statements that may be deemed
"forward-looking statements" within the meaning of Section 27A of the Securities
Act and Section 21E of the Exchange Act. All statements other than statements of
historical facts, included in this Annual Report that relate to business plans
or strategies, projected or anticipated benefits or other consequences of such
plans or strategies, projected or anticipated benefits from acquisitions made by
or to be made by CDI or projections involving anticipated revenues, earnings, or
other aspects of operating results are forward-looking statements. The words
"expect," "believe," "anticipate," "project," "estimate," and similar
expressions are intended to identify forward-looking statements. The Company
cautions readers that such statements are not guarantees of future performance
or events and are subject to a number of factors that may tend to influence the
accuracy of the statements and the projections upon which the statements are
based, including but not limited to those discussed below. As noted elsewhere,
all phases of CDI's operations are subject to a number of uncertainties, risks
and other influences, many of which are outside the control of CDI, and any one
or a combination of which could materially affect the results of CDI's
operations and the accuracy of forward-looking statements made by CDI. The
following discussion outlines certain factors that could affect CDI's
consolidated results of operations for 1999 and beyond and cause them to differ
materially from those that may be set forth in forward-looking statements made
by or on behalf of the Company.
LOW OIL AND NATURAL GAS PRICES AND CYCLICALITY OF THE OIL AND GAS INDUSTRY
The Company's business is substantially dependent upon the condition of
the oil and gas industry and, in particular, the willingness of oil and gas
companies to make capital expenditures on exploration, drilling and production
operations offshore. The level of capital expenditures is generally dependent on
the prevailing view of future oil and gas prices, which are influenced by
numerous factors affecting the supply and demand for oil and gas, including
worldwide economic activity, interest rates and the cost of capital,
environmental regulation, tax policies, coordination by the Organization of
Petroleum Exporting Countries ("OPEC"), the cost of exploring for and producing
oil and gas, the sale and expiration dates of offshore leases in the United
States and overseas, the discovery rate of new oil and gas reserves in offshore
areas and technological advances. Oil
12
and gas prices and the level of offshore drilling and production activity have
recently dropped significantly. There can be no assurance that activity levels
will increase any time soon. A sustained period of low hydrocarbon prices would
likely have a material adverse effect on the Company's financial position and
results of operations.
VESSEL OPERATING RISKS AND LIMITATION OF INSURANCE COVERAGE
Marine construction involves a high degree of operational risk. Hazards,
such as vessels sinking, grounding, colliding and sustaining damage from severe
weather conditions are inherent in marine operations. These hazards can cause
personal injury or loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.
Damage arising from such an occurrence may result in lawsuits asserting large
claims. CDI maintains such insurance protection as it deems prudent, including
Jones Act employee coverage (the maritime equivalent of workers compensation)
and hull insurance on its vessels. There can be no assurance that any such
insurance will be sufficient or effective under all circumstances or against all
hazards to which CDI may be subject. A successful claim for which CDI is not
fully insured could have a material adverse effect on the Company. Moreover, no
assurance can be given that CDI will be able to maintain adequate insurance in
the future at rates that it considers reasonable. As construction activity moves
into deeper water in the Gulf of Mexico, construction projects tend to be larger
and more complex than shallow water projects. As a result, the Company's
revenues and profits are increasingly dependent on its larger vessels. While the
Company currently insures its vessels against property loss due to a
catastrophic marine disaster, mechanical failure or collision, the loss of any
of the Company's large vessels as a result of such event could result in a
substantial loss of revenues, increased costs and other liabilities and could
have a material adverse effect on the Company's operating performance.
SEASONALITY AND ADVERSE WEATHER RISKS
Marine operations conducted in the Gulf of Mexico are seasonal and depend,
in part, on weather conditions. Historically, CDI has enjoyed its highest vessel
utilization rates during the summer and fall of the year when weather conditions
are favorable for offshore exploration, development and construction activities
and has experienced its lowest utilization rates in the first quarter. During
certain periods of the year, CDI typically bears the risk of delays caused by
adverse weather conditions. Accordingly, the results of any one quarter are not
necessarily indicative of annual results or continuing trends.
CONTRACT BIDDING AND ALLIANCE RISKS
A majority of CDI's projects are currently performed on a qualified
turnkey basis. The revenue, cost and gross profit realized on a contract can
vary from the estimated amount because of changes in offshore job conditions,
variations in labor and equipment productivity from the original estimates and
performance of others such as alliance partners. These variations and risks
inherent in the marine construction industry may result in CDI experiencing
reduced profitability or losses on projects. Although CDI has entered into a
number of strategic alliances, there can be no assurance that CDI will be able
to enter into such alliances in the future, that these alliances will be
successful or that contracts resulting from these alliances will not result in
unforeseen operational difficulties.
UNCERTAINTY OF ESTIMATES OF NATURAL GAS AND OIL RESERVES
This Annual Report contains an estimate of the Company's proved natural
gas and oil reserves and the estimated future net cash flows therefrom based
upon a report prepared as of December 31, 1998 by Miller & Lents, which report
relies upon various assumptions, including assumptions required by the
Commission as
13
to natural gas and oil prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. The process of estimating natural
gas and oil reserves is complex, requiring significant decisions and assumptions
in the evaluation of available geological, geophysical, engineering and economic
data for each reservoir. As a result, such estimates are inherently imprecise.
Actual future production, cash flows, development expenditures, operating
expenses and quantities of recoverable natural gas and oil reserves may vary
substantially from those estimated in the report. Any significant variance in
these assumptions could materially affect the estimated quantity and value of
the Company's proved reserves.
NATURAL GAS AND OIL OPERATING RISKS
The Company's natural gas and oil operations are subject to the usual
risks incident to the operation of natural gas and oil wells, including, but not
limited to, uncontrollable flows of oil, natural gas, brine or well fluids into
the environment, blowouts, cratering, mechanical difficulties, fires,
explosions, pollution and other risks, any of which could result in substantial
losses to the Company. In accordance with industry practice, CDI maintains
insurance against some, but not all, of the risks described above.
COMPETITION
The business in which the Company operates is highly competitive. Several
of the Company's competitors are companies that are substantially larger and
have greater financial and other resources than the Company. If other companies
relocate or acquire vessels for operations in the Gulf of Mexico, levels of
competition may increase and the Company's business could be adversely affected.
CUSTOMER CONCENTRATION
CDI's customers consist primarily of major and independent natural gas and
oil producers, pipeline transmission companies and offshore engineering and
construction companies. During 1997, the Company derived approximately 19% of
its consolidated revenues from one customer and 11% from another. CDI derived
11% of its consolidated revenue in 1998 from another customer. While CDI
currently has a good relationship with its customers, the loss of any one of its
largest customers, or a sustained decrease in demand, could result in a
substantial loss of revenues and could have a material adverse effect on CDI's
operating performance. While losses from customer inability to pay (bad debt
expenses) have historically been insignificant, the current downturn in
commodity prices could result in bankruptcy or liquidation of certain of the
smaller production companies that operate in the Gulf.
DEPENDENCE ON KEY PERSONNEL AND RETENTION OF EMPLOYEES
CDI's success depends on the continued active participation of key
management personnel. The loss of key people could adversely affect CDI's
operations. The Company has two-year employment and non-compete agreements with
twelve of its senior officers. CDI believes that its success and continued
growth is also dependent upon its ability to employ and retain skilled
personnel. While the Company believes that its wage rates are competitive and
that its relationship with its workforce is good, a significant increase in the
wages paid by other employers could result in a reduction in the Company's
workforce, increases in the wage rates paid by the Company, or both. If either
of these events occur for any significant period of time, the Company's
profitability could be diminished and the growth potential of the Company could
be impaired.
REGULATORY AND ENVIRONMENTAL MATTERS
CDI's subsea construction, inspection, maintenance and decommissioning
operations and its natural gas
14
and oil production from offshore properties (including decommissioning of such
properties) are subject to and affected by various types of government
regulation, including numerous federal, state and local environmental protection
laws and regulations. These laws and regulations are becoming increasingly
complex, stringent and expensive and there can be no assurance that continued
compliance with existing or future laws or regulations will not adversely affect
the operations of CDI. Significant fines and penalties may be imposed for
non-compliance.
ANTI-TAKEOVER CONSIDERATIONS
The Board of Directors of CDI has the authority, without any action by the
shareholders, to fix the rights and preferences on up to 5,000,000 shares of
undesignated preferred stock, including dividend, liquidation and voting rights.
In addition, CDI's Articles of Incorporation divide the Company's Board of
Directors into three classes. Except for a transaction involving Coflexip (which
is specifically excluded), CDI also is subject to certain anti-takeover
provisions of the Minnesota Business Corporations Act ("MBCA"). In addition, CDI
is a party to a Shareholders Agreement that provides Coflexip with a right of
first refusal in connection with certain acquisition proposals for CDI and has
employment contracts with twelve (12) of its officers which require cash
payments in the event of a "change of control". Any or all of the provisions or
factors described above may have the effect of discouraging a takeover proposal
or tender offer not approved by management and the Board of Directors of CDI,
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.
15
ITEM 2. PROPERTIES
MARINE VESSELS AND EQUIPMENT
GENERAL
The Company owns a fleet of 11 vessels and two ROVs. The size of the
Company's fleet and its capabilities have increased in recent years with the
addition of the WITCH QUEEN, BALMORAL SEA, UNCLE JOHN, SEA SORCERESS and MERLIN.
Management believes that the Gulf of Mexico market increasingly will
require specially designed or equipped vessels to deliver the necessary subsea
construction services, especially in the Deepwater. Six of CDI's vessels have
the permanent capability to provide SAT diving services. Four of CDI's vessels
have DP capabilities specifically designed to respond to the Deepwater market.
NEW VESSELS
In 1998, the design of CDI's new MSV, the Q4000 was refined to include
more features. It is a sixth generation, multi-service vessel which is a newer
version of the MSV UNCLE JOHN'S column stabilized, semisubmersible design and is
unique due to the absence of lower hull cross bracing which decreases vessel
weight and increases operating efficiency. Variable deck load of 4,000 tons and
a large deck area would make the vessel particularly well suited for large
offshore construction projects in Deepwater. High transit speed would allow it
to move rapidly from one location to another while operability (thruster power
and motion characteristics) would provide for well intervention in an extremely
cost effective manner. Management expects that there would be a derrick similar
to that installed on the MSV UNCLE JOHN for well completion and well servicing
projects. Final evaluation is scheduled for mid-1999 but there is no assurance
that the Q4000 will be constructed.
The DSV SEA SORCERESS began a contract in the third quarter of 1998 to
assist a large new field development project offshore of Newfoundland, Canada.
This contract was cancelled in early 1999. Due to the cancellation, it is
expected this vessel may remain idle for some time. The vessel was purchased as
a candidate to convert to DP and target Deepwater heavy construction projects.
Long lead time components such as the thrusters have been purchased and the
engineering completed so the Company believes the conversion can be completed in
a six to nine month time frame. However, this $30 to $35 million capital
expenditure will not be undertaken until commodity prices and market conditions
improve.
In early 1998, CDI contracted to have a replacement vessel built for its
utility boat CAL DIVER IV as part of its ongoing program to upgrade the quality
of its fleet. The original CAL DIVER IV was sold to Aquatica, Inc. in January
1999. The new vessel is 120 feet long, 32 feet wide, has 1,440 feet of clear
deck space, a 60 ton deck load capacity and galley accommodations for 24 people.
It will be capable of 10 knots cruising speed and is expected to be delivered in
mid-1999.
16
CAL DIVE INTERNATIONAL, INC.
LISTING OF VESSELS, BARGES AND ROVS
AS OF DECEMBER 31, 1998
DATE MOONPOOL
PLACED IN CLEAR DECK LAUNCH/
SERVICE LENGTH SPACE DECK LOAD ACCOMMO- SAT CLASSIFI-
BY CDI (FEET) (SQ. FEET) (TONS) DATIONS DIVING CRANE CATION (3)
------ ------ ---------- ------ ------- ------ ----- ----------
DP MSV:
Uncle John .......................... 11/96 254 11,863 460 102 X 2 x 100- DNV
ton
DP DSVs:
Balmoral Sea(1)...................... 9/94 259 3,443 250 60 X 30-ton DNV
Witch Queen.......................... 1/95 278 5,600 500 62 X 50-ton DNV
Merlin........... ................... 12/97 198 955 308 42 A-Frame ABS
DSVs:
Cal Diver I.......................... 7/84 196 2,400 220 40 X 20-ton ABS
Cal Diver II......................... 6/85 166 2,816 300 32 X A-Frame ABS
Cal Diver III........................ 8/87 115 1,320 105 18 -- -- ABS
Cal Diver IV(2)...................... 1999 120 1,440 60 24 -- -- ABS
Cal Diver V.......................... 9/91 168 2,324 490 30 -- A-Frame ABS
Other:
Sea Sorceress........................ 8/97 374 8,600 10,000 50 X -- DNV
Cal Dive Barge I..................... 8/90 150 NA 200 26 -- 200-ton ABS
ROVs x 2............................. 4/97 25 -- -- -- -- --
Mobile SAT System ................... 2/99 -- -- -- -- X -- ABS
(1) This vessel was operated by the Company under charters from September 1994
to February 1995 and from April 1996 to August 8, 1996, at which time it
was acquired by the Company.
(2) Delivery of this vessel is expected in mid-1999.
(3) Under government regulations and CDI's insurance policies, the Company is
required to maintain its vessels in accordance with standards of
seaworthiness and safety set by government regulations and classification
organizations. CDI maintains its fleet to the standards for seaworthiness,
safety and health set by both the American Bureau of Shipping ("ABS"), Det
Norske Veritas ("DNV") and the United States Coast Guard ("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.
CDI incurs routine drydock inspection, maintenance and repair costs under
USCG Regulations and to maintain ABS or DNV classification for its vessels. In
addition to complying with these requirements, the Company has its own vessel
maintenance program which management believes permits Cal Dive to continue to
provide its customers with well maintained, reliable vessels. In the normal
course of its operations, the Company also charters other vessels on a
short-term basis, such as tugboats, cargo barges, utility boats and dive support
vessels. All of the Company's vessels are subject to ship mortgages.
SUMMARY OF NATURAL GAS AND OIL RESERVE DATA
17
The table below sets forth information, as of December 31, 1998, with
respect to the Company's estimated net proved reserves and the present value of
estimated future net cash flows at such date, based on estimates by Miller &
Lents.
TOTAL PROVED(1)
---------------
(DOLLARS IN
THOUSANDS)
Estimated Proved Reserves:
Natural Gas (MMcf)............... 22,434
Oil and Condensate (MBbls)....... 70
Standardized measure of discounted
future net cash flows(2)............ $10,156
(1) Seventeen (17) blocks purchased in 1999 described below are not included in
the above December 31, 1998 summary. As a result of this purchase, ERT's
Estimated Proven Reserves have increased approximately 32% to 29,300 MMCF
of natural gas and 152 MBbls of oil and the standardized measure of
discounted future net cash flow has increased to $22,779.
(2) The standardized measure of discounted future net cash flows attributable
to the Company's reserves was prepared using constant prices as of the
calculation date, discounted at 10% per annum.
As of March 19, 1999, the Company owned an interest in 145 gross (125 net)
natural gas wells and 45 gross (25 net) oil wells located in federal offshore
waters in the Gulf of Mexico.
FACILITIES
CDI is headquartered at 400 N. Sam Houston Parkway E., in Houston, Texas.
The Company's subsea and marine services operations are based in Morgan City,
Louisiana. All of CDI's facilities are leased.
PROPERTY AND FACILITIES SUMMARY
LOCATION FUNCTION SIZE
-------- -------- ----
Houston, Texas............. Corporate and ERT Headquarters 37,800 square feet
Project Management
Sales Office
Morgan City, Louisiana..... Operations/Docking 28.5 acres
Warehouse 30,000 square feet
Offices 4,500 square feet
The Company also has sales offices in Lafayette and New Orleans, Louisiana.
18
ITEM 3. LEGAL PROCEEDINGS.
CDI's operations are subject to the inherent risks of offshore marine
activity, including accidents resulting in personal injury and the loss of life
or property, environmental mishaps, mechanical failures and collisions. The
Company insures against these risks at levels consistent with industry
standards. CDI believes its insurance is adequate to protect it against, among
other things, the cost of replacing the total or constructive total loss of its
vessels. The Company also carries workers' compensation, maritime employer's
liability, general liability and other insurance customary in its business. All
insurance is carried at levels of coverage and deductibles that CDI considers
financially prudent. CDI's services are provided in hazardous environments where
accidents involving catastrophic damage or loss of life could result, and
litigation arising from such an event may result in the Company being named a
defendant in lawsuits asserting large claims. To date, the Company has been
involved in no such catastrophic lawsuit. Although there can be no assurance
that the amount of insurance carried by CDI is sufficient to protect it fully in
all events, management believes that its insurance protection is adequate for
the Company's business operations. A successful liability claim for which CDI is
underinsured or uninsured could have a material adverse effect on the Company.
CDI is 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, the Company from time
to time incurs other claims, such as contract disputes, in the normal course of
business. The Company believes that the outcome of all such proceedings, even if
determined adversely, would not have a material adverse effect on its business
or financial condition.
ITEM 4. SUBMISSION OF MAKERS TO A VOTE OF SECURITY HOLDERS.
None.
19
ITEM (UNNUMBERED). EXECUTIVE OFFICERS OF THE COMPANY
The following table sets forth certain information as of December 31, 1998 with
respect to the executive officers and certain other senior officers of the
Company:
NAME AGE POSITION WITH THE COMPANY
---- --- -------------------------
Owen Kratz........................ 44 Chairman and Chief Executive Officer
Martin R. Ferron.................. 42 President and Chief Operating Officer
S. James Nelson, Jr............... 56 Executive Vice President and Chief
Financial Officer
Andrew C. Becher.................. 53 Senior Vice President, General
Counsel and Secretary
Louis L. Tapscott ................ 61 Senior Vice President -- Business
Development
Kenneth Duell..................... 47 Senior Vice President -- Integrated
Services
Lyle K. Kuntz .................... 46 President, ERT
OWEN KRATZ has served as the Company's Chairman since May of 1998, Chief
Executive Officer since April 1997, President since 1993 and Chief Operating
Officer and director since 1990. He joined the Company in 1984 and has held
various offshore positions, including SAT diving supervisor, and management
responsibility for client relations, marketing and estimating. From 1982 to
1983, Mr. Kratz was the owner of an independent marine construction company
operating in the Bay of Campeche. Prior to 1982, he was a supervisor for various
international diving companies and a SAT diver in the North Sea.
MARTIN R. FERRON became President in February of 1999 and has served as Chief
Operating Officer since January 1998. Mr. Ferron has almost twenty years of
experience in the oilfield industry, seven of which were in senior management
positions with international operations of McDermott Marine Construction and
Oceaneering International Services Limited. Mr. Ferron has a Civil Engineering
degree from the City University in London, a Masters Degree in Marine Technology
from Strathclyde University in Glasgow, and an MBA from Aberdeen University,
Scotland and is a Chartered Civil Engineer.
S. JAMES NELSON, JR., has served as Executive Vice President and Chief Financial
Officer of the Company since 1990. From 1985 to 1988, Mr. Nelson was the Senior
Vice President and Chief Financial Officer of Diversified Energies, Inc., the
former parent of Cal Dive, at which time he had corporate responsibility for the
Company. From 1980 to 1985, Mr. Nelson served as Chief Financial Officer of
Apache Corporation, an oil and gas exploration and production company. From 1966
to 1980, Mr. Nelson was employed with Arthur Andersen & Co., and from 1976 to
1980, he was a partner serving on the firm's worldwide oil and gas industry
team. Mr. Nelson received his undergraduate degree from Holy Cross College
(B.S.) in 1964 and a masters in business administration (M.B.A.) from Harvard
University in 1966.
ANDREW C. BECHER has served as Senior Vice President, General Counsel and
Secretary of the Company since January 1996. Mr. Becher served as outside
general counsel for the Company from 1990 to 1996, while a partner with the
national law firm Robins, Kaplan, Miller & Ciresi. From 1987 to 1990, Mr. Becher
served as Senior Vice President of Dain Raucher, Inc., a regional investment
banking firm. From 1976 to 1987, he was a partner specializing in mergers and
acquisitions with the law firm of Briggs and Morgan.
LOUIS L. TAPSCOTT joined the Company as Senior Vice President of Business
Development in August 1996. From 1992 to 1996, he was a Senior Vice President
for Sonsub International, Inc., a company which operates
20
a Deepwater fleet of ROVs. From 1984 to 1988, he was a director and Chief
Operating Officer of Oceaneering International, Inc. Mr. Tapscott has over
thirty years of executive management and operational experience working with
subsea contractors and subsea technology organizations in the United States and
internationally.
KENNETH DUELL joined Cal Dive in November of 1994 and was appointed Senior Vice
President -- Integrated Services in 1997. From 1989 to 1994, he was employed by
ABB Soimi, Milan, Italy, in connection with a modular refining systems
development in Central Asia. From 1974 to 1988, he held various positions with
Santa Fe International, including the ROV and diving division. Mr. Duell has
over 22 years of worldwide experience in all aspects of the onshore and offshore
construction and diving industry.
LYLE KUNTZ has served as President of the Company's subsidiary, Energy Resource
Technology, Inc., since its inception in 1992. Prior to forming ERT, Mr. Kuntz
spent 17 years with ARCO Oil and Gas Co. in a broad range of senior engineering
and management positions.
21
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS.
CDI's Common Stock is traded in the U.S. on the Nasdaq National Market
("Nasdaq"). The Common Stock is quoted through Nasdaq under the symbol "CDIS."
The following table represents for the periods indicated, the high and low sales
price per share of the Company's Common Stock:
HIGH LOW
---- ---
Fiscal Year 1997
Third quarter(1) .................... $ 37.75 $ 19.75
Fourth quarter ...................... 37.875 22.25
Fiscal Year 1998
First quarter ....................... $ 33.00 $ 23.25
Second quarter ...................... 40.00 27.50
Third quarter ....................... 28.50 11.125
Fourth quarter ...................... 23.50 10.625
(1) CDI completed its initial public offering on July 7, 1997 and trading
information in the third quarter of 1997 is reported only after that date.
As of March 19, 1999 there were approximately 2,640 holders of record of
Common Stock.
CDI has never paid cash dividends on its Common Stock and does not intend
to pay cash dividends in the foreseeable future. The Company currently intends
to retain earnings, if any, for the future operation and growth of its business.
Certain of CDI's financing arrangements restrict the payment of cash dividends
under certain circumstances. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources".
In February and March of 1998, 35,000 shares of the Company's common stock
were issued in connection with the exercise of employee stock options pursuant
to s.4(2) of the Securities Act of 1933.
22
ITEM 6. SELECTED FINANCIAL DATA
The financial data presented below for each of the five years ended
December 31, 1998, should be read in conjunction with Management's Discussion
and Analysis of Financial Condition and Results of Operations and the
Consolidated Financial Statements and Notes to Consolidated Financial Statements
included elsewhere in this Form 10-K.
YEAR ENDED DECEMBER 31,
-----------------------
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net Revenues ............ $ 38,032 $ 37,524 $ 76,122 $109,386 $151,887
Gross Profit ............ 10,961 8,849 22,086 33,685 49,209
Net Income .............. 4,034 2,674 8,435 14,482 24,125
Net Income Per Share:
Basic .............. 0.48 0.24 0.76 1.12 1.66
Diluted ............ 0.46 0.24 0.75 1.09 1.61
Total Assets ............ 28,633 44,859 83,056 125,600 164,235
Working Capital ......... 6,052 4,033 13,409 28,927 45,916
Long-Term Debt .......... 3,766 5,300 25,000 -- --
Shareholders' Equity .... 10,394 22,408 30,844 89,369 113,643
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
Natural gas and oil prices, the offshore mobile rig count and Gulf of
Mexico lease activity are three of the primary indicators management uses to
predict the level of the Company's business. CDI's construction services
generally follow successful drilling activities by six to eighteen months on the
Continental Shelf and twelve to twenty-four in the Deepwater arena. The level of
drilling activity is related to both short and long-term trends in natural gas
and oil prices. Recently commodity prices have declined significantly resulting
in the utilization of offshore mobile rigs dropping to approximately 70% in
contrast to almost full utilization in 1997 and the first half of 1998. Should
this period of low oil and gas prices persist, demand for the Company's services
could be negatively impacted in 1999.
Product prices impact the Company's natural gas and oil operations in
several respects. The Company seeks to acquire producing natural gas and oil
properties that are generally in the later stages of their economic life. These
properties typically have few, if any, unexplored drilling locations, so the
potential abandonment liability is a significant consideration with respect to
the offshore properties which the Company has purchased to date. Although higher
natural gas prices tend to reduce the number of mature properties available for
sale, these higher prices contributed to improved operating results for the
Company in 1996 and 1997. In contrast, lower natural gas prices, as experienced
in 1998, contributed to lower operating results for ERT in 1998 and has
increased the number of mature properties available for sale such that the
Company has completed three transactions involving interests in 17 offshore
blocks early in 1999. Salvage operations consist of platform decommissioning,
removal and abandonment and P&A services performed by the Company's salvage
assets, i.e., a stiff-leg derrick barge and well servicing equipment. In
addition, salvage related support, such as debris removal and preparation of
platform legs for removal, is often provided by the Company's surface diving
vessels. In 1989, management targeted platform removal and salvage operations as
a regulatory driven activity which offers a partial hedge against fluctuations
in the commodity price of natural gas. In particular, MMS regulations require
removal of platforms within twelve months after lease expiration and also
require remediation of the seabed at the well site to its original state. The
Company contracts and manages, on a turnkey basis, all aspects of the
decommissioning and abandonment of fields of all sizes using third party heavy
lift derrick barges if necessary. The Company has entered into an alliance with
Horizon Offshore gaining
23
access to expanded derrick barge and pipelay capacity. In this regard Cal Dive
has guaranteed a certain level of barge activity which it expects to use in
conjunction with CDI salvage operations.
The following table sets forth for the periods presented (i) average U.S.
natural gas prices, (ii) the Company's natural gas production, (iii) the average
number of offshore rigs under contract in the Gulf of Mexico, (iv) the number of
platforms installed and removed in the Gulf of Mexico and (v) the vessel
utilization rates for each of the major categories of the Company's fleet.
1996 1997 1998
---- ---- ----
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
-- -- -- -- -- -- -- -- -- -- -- --
U.S. Natural Gas Prices(1) ............ $3.16 $2.37 $2.15 $2.81 $2.67 $2.13 $2.46 $2.88 $2.18 $2.26 $2.03 $1.92
ERT Gas Production (MMCF) ............ 970 918 1,169 1,253 1,519 1,213 1,381 1,252 1,489 1,163 803 1,080
Rigs Under Contract in the Gulf of
Mexico(2) ............................ 149 156 161 164 165 169 168 169 170 167 149 137
Platform Installations(3) ............ 12 35 31 30 16 21 29 39 18 16 21 20
Platform Removals(3) ................. 11 11 25 30 3 21 31 28 3 15 24 8
Average Company Vessel Utilization
Rate(4)
Dynamic Positioned .................. 81% 71% 82% 92% 60% 79% 92% 94% 75% 64% 85% 80%
Saturation DSV ...................... 55% 73% 82% 88% 58% 77% 81% 77% 88% 79% 70% 83%
Surface Diving ...................... 62% 77% 85% 74% 53% 80% 90% 81% 33% 58% 72% 76%
Derrick Barge ....................... 16% 57% 91% 65% 22% 78% 99% 89% 28% 73% 70% 70%
(1) Average of the monthly Henry Hub cash prices in $ per Mcf, as
reported in Natural Gas Week.
(2) Average monthly number of rigs contracted, as reported by Offshore
Data Services.
(3) Source: Offshore Data Services; installation and removal of platforms
with two or more piles in the Gulf of Mexico.
(4) Average vessel utilization rate is calculated by dividing the total
number of days the vessels in this category generated revenues by the
total number of days in each quarter.
Vessel utilization is historically lower during the first quarter due to
winter weather conditions in the Gulf of Mexico. Accordingly, the Company plans
its drydock inspections and other routine and preventive maintenance programs
during this period. During the first quarter, a substantial number of the
Company's customers finalize capital budgets and solicit bids for construction
projects. The bid and award process during the first two quarters leads to the
commencement of construction activities during the second and third quarters. As
a result, the Company has historically generated more than 50% (up to 65%) of
its consolidated revenues in the last six months of the year. The Company's
operations can also be severely impacted by weather during the fourth quarter.
The Company's salvage barge, which has a shallow draft, is particularly
sensitive to adverse weather conditions, and its utilization rate will be lower
during such periods. To minimize the impact of weather conditions on the
Company's operations and financial condition, CDI began operating DP vessels and
expanded into the acquisition of mature offshore properties. The unique station-
keeping ability offered by dynamic positioning enables these vessels to operate
throughout the winter months and in rough seas. Operation of natural gas and oil
properties tends to offset the impact of weather since the first and fourth
quarters are typically periods of high demand for natural gas and of strong
natural gas prices. Due to this seasonality, full year results are not likely to
be a direct multiple of any particular quarter or combination of quarters.
24
RESULTS OF OPERATIONS
COMPARISON OF YEAR ENDED DECEMBER 31, 1998 TO YEAR ENDED DECEMBER 31, 1997
REVENUES. Consolidated revenues of $151.9 million in 1998 were 39% more
than the $109.4 million earned during 1997 with the Subsea operations
contributing all of the increase while natural gas and oil production revenues
declined $3.9 million. All of the increase was due to increased demand for
services provided by CDI's DP vessels, particularly the UNCLE JOHN, WITCH QUEEN
and BALMORAL SEA which together contributed 62% of the increase. In addition,
new vessels (SEA SORCERESS and MERLIN) contributed $10.3 million of the
increase. The charter of two Coflexip Stena Offshore vessels, the MARIANOS
during the first quarter and the CONSTRUCTOR in the second, added $8.0 million
to the 1998 revenues.
Natural gas and oil production was $12.6 million in 1998 as compared to
$16.5 million in 1997. The decrease was due to a decline in production from 5.7
BCFE (billion of cubic feet equivalent) during 1997 to 4.9 BCFE in 1998 and a
decline in average gas prices from $2.57/Mcf for 1997 to $2.12/Mcf during 1998.
The decline in production is a result of five wells going off line in the second
quarter and remedial work being delayed into the fourth quarter by a lack of
equipment and then by weather.
GROSS PROFIT. Gross profit increased by $15.5 million, or 46%, from $33.7
million in 1997 to $49.2 million in 1998 with the UNCLE JOHN, WITCH QUEEN and
BALMORAL SEA making up the majority of the increase. The remaining increase was
due to improved demand for the two saturation diving vessels and the vessels
which work in the shallow Gulf of Mexico (from the shore to 300 feet of water).
Subsea and salvage margins increased from 27% in 1997 to 33% during 1998 due
mainly to outstanding offshore performance and demand for the DP vessels.
Natural gas and oil production gross profit was $3.5 million in 1998 as
compared to $8.4 million in the prior year. The decrease was due to the
aforementioned declines in average natural gas prices and production during 1998
as compared to 1997 and to expensive efforts to re-establish production in the
second half of the year.
SELLING AND ADMINISTRATIVE EXPENSES. Selling and administrative expenses
increased $4.6 million to $15.8 million in 1998 as compared to 1997. The $15.8
million includes a $4.5 million provision principally for 1998 incentive
compensation compared to $2.9 million provided in 1997. The remainder of the
increase is due to the addition of new personnel to support the Company's
Deepwater strategy, growth in it base business and to the cost of a supply chain
management consulting project. Selling and administrative costs were 10% of
revenues in 1998, a level identical to that in 1997.
OTHER INCOME AND EXPENSES. The Company recorded $2.6 million in 1998
reflecting its share of earnings of Aquatica, Inc. Net interest income and other
of $1.1 million for 1998 compares to $208,000 of net interest expense and other
for 1997. This improvement was due to the Company remaining debt free since
completion of its initial public offering of common stock in July, 1997.
INCOME TAXES. Income taxes were $13 million in 1998 as compared to $7.8
million for the prior year. The increase was due to the Company's increased
profitability as the effective tax rate remained 35% in both years. Roughly 35%
of the 1998 tax provision was deferred due mainly to increased depreciation in
addition to the Company's Deepwater research and development efforts.
NET INCOME. Net income increased 67% to $24.1 million in 1998 as compared
to $14.5 million in 1997 as a result of factors described above. Diluted
earnings per share increased 48% (19 percentage points less than the net income
increase) in 1998, as compared to 1997, due to the impact on weighted average
common
25
shares outstanding of the new shares issued in the July 1997 IPO.
COMPARISON OF YEAR ENDED DECEMBER 31, 1997 TO YEAR ENDED DECEMBER 31, 1996
REVENUES. Consolidated revenues of $109.4 million in 1997 were 44% more
than the $76.1 million reported during 1996 due primarily to the addition of DP
vessels, improved demand for traditional subsea services and increased natural
gas and oil production. Revenues from DP vessels increased 89% to $47.6 million
in 1997 as compared to prior year due to the full year operations of the
BALMORAL SEA and UNCLE JOHN (vessels placed in service in April and October,
1996, respectively). This increase, combined with stronger market conditions for
surface diving and supply boats offset the impact of seven vessels being out of
service for a combined 40 weeks during the first two quarters of 1997 for
regulatory inspections, preventative maintenance and/or vessel upgrades. In
addition, six weeks of downtime were experienced during the third quarter of
1997 due to a lightning strike on the WITCH QUEEN and an electrical fire on the
CAL DIVER II. During 1996 only two CDI vessels were out of service for any
significant length of time.
Revenue from natural gas and oil production was $16.5 million for the year
ended 1997 from 13 properties as compared to $12.3 million in 1996 from nine
properties. The 1997 revenue benefited from prior year well enhancement efforts.
Average gas sales prices improved slightly in 1997 compared to 1996.
GROSS PROFIT. Gross profit increased by $11.6 million, or 53%, from $22.1
million in 1996 to $33.7 million in 1997. The addition of the UNCLE JOHN and
BALMORAL SEA to the Company's fleet were responsible for over half of the
increase. The remaining increase was due to improved demand for traditional
subsea services and increased natural gas and oil production. Subsea margins
were unchanged between 1997 and 1996 despite the Company encountering
difficulties on a large construction project in the third quarter of 1997 and
the unusually active 1997 regulatory inspection and maintenance program which
resulted in Subsea repair costs of $6.3 million as compared to $3.4 million in
1996.
Natural gas and oil production gross profit was $8.4 million for the year
ended December 31, 1997 as compared to $5.0 million for the prior year. The
increase was due mainly to the acquisition of five blocks during the second half
of 1996 and the gain recorded on the sale of two properties during the second
quarter of 1997.
SELLING & ADMINISTRATIVE EXPENSES. Selling and administrative expenses
increased 35% to $11.2 million in 1997 as compared to 1996. The increase was due
mainly to the addition of new personnel to support the Company's Deepwater
strategy and growth in its base business and to higher levels of Subsea bonuses.
The remainder of the increase was due to the ERT incentive compensation program
whereby key management personnel share in the improved earnings of the natural
gas and oil production segment. Selling and administrative expenses were 10% of
1997 revenues, an improvement from 11% in 1996.
NET INTEREST. Net interest expense decreased by $622,000 (from $745,000 in
1996 to $123,000 in 1997) due mainly to the Company retiring all debt in July
1997 with the proceeds received from the IPO. Borrowings under the Revolving
Credit Agreement averaged $10.4 million during 1997 as compared to $13.0 million
during 1996.
INCOME TAXES. Income taxes were $7.8 million for 1997 as compared to $4.6
million for the prior year. The increase was due to the Company's increased
profitability. Higher depreciation related to the newly acquired DP vessels
resulted in a reduction of the amount of cash taxes paid (as a percentage of
pre-tax income) in 1997 compared to 1996 and also a corresponding increase in
the deferred tax liability.
NET INCOME. Net income increased 72% to $14.5 million for the year ended
December 31, 1997 as compared to $8.4 million in 1996 as a result of factors
described above.
26
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically funded its operating activities principally
from internally generated cash flow, even during industry-depressed years such
as 1992 and 1998. An initial public offering of common stock was completed on
July 7, 1997, with the sale of 2,875,000 shares generating net proceeds to the
Company of approximately $39.5 million, net of underwriting discounts and
issuance costs. The proceeds were used to fund capital expenditures during 1997,
and to repay all outstanding long-term indebtedness. As of December 31, 1998,
the Company had $45.9 million of working capital (including $32.8 million of
cash on hand) and no debt outstanding after funding the equity investment in
Aquatica and $14.9 million of capital expenditures in 1998, which includes ERT's
purchase of six blocks offshore. Subsequent to year end CDI's cash on hand
increased to $42 million at January 31, 1999. Additionally, CDI has
approximately $40 million available under a Revolving Credit Agreement.
OPERATING ACTIVITIES. Net cash provided by operating activities was $35.7
million in 1998, as compared to $22.3 million provided in 1997. This increase is
primarily the result of increased profitability of the Company and a decline in
the level of funding required to fund accounts receivable increases ($5.8
million required in 1997 compared to $900,000 returned in 1998). Other current
assets increased $4.2 million at December 31, 1998 as compared to December 31,
1997 due mainly to the purchases of materials and supplies for the new Full
Field Development program.
The Company experienced improved collections of its accounts receivable
during 1998 as compared to the prior year. Total accounts receivable decreased
$900,000 at December 31, 1998 as compared to December 31, 1997 while revenues
grew 39% in 1998 compared to 1997. The Company's average number of days to bill
and collect its trade receivables decreased by 10 days in 1998 as compared to
1997. While losses from customer inability to pay (bad debt expenses) have
historically been insignificant, the current downturn in commodity prices could
result in bankruptcy or liquidation of certain of the smaller production
companies that operate in the Gulf.
Net cash provided by operating activities was $22.3 million in 1997, as
compared to $7.6 million provided in 1996. This increase was primarily the
result of increased profitability and a decline in the level of funding required
to fund accounts receivable increases ($5.8 million required in 1997 compared to
$15.3 million in 1996). In addition, depreciation and amortization increased as
a result of vessel and natural gas and oil properties acquisitions.
INVESTING ACTIVITIES. Capital expenditures have consisted principally of
strategic asset acquisitions, the assembly of a fleet of DP vessels, including
the WITCH QUEEN, BALMORAL SEA, UNCLE JOHN, SEA SORCERESS and MERLIN,
improvements to existing vessels and the acquisition of offshore natural gas and
oil properties. The Company incurred $14.9 million of capital expenditures
during 1998. In January 1998, ERT acquired interests in six blocks involving two
separate fields from Sonat Exploration Company for $1.0 million and assumption
of Sonat's pro rata share of the related decommissioning liability. The
remaining balance includes costs associated with placing the MERLIN in service
and additions to the SEA SORCERESS in preparation for the Terra Nova project as
well as the cost of new steel and equipment added to the WITCH QUEEN, BALMORAL
SEA and CAL DIVER V during 1998 drydock inspections.
In February 1998, the Company purchased a significant minority equity
investment in Aquatica, Inc. (a surface diving company) for $5.0 million, in
addition to a commitment to lend additional funds of $5.0 million to allow
Aquatica to purchase vessels and fund other growth opportunities. Dependent upon
various preconditions, as defined, the shareholders of Aquatica have the right
to convert their shares into Cal Dive shares at a ratio based on a formula
which, among other things, values their interest in Aquatica and must be
accretive to Cal Dive shareholders.
27
The Company incurred $28.9 million of capital expenditures during 1997.
During the third quarter, the Company acquired a 374 foot by 104 foot
ice-strengthened vessel (the SEA SORCERESS) as a DP conversion candidate. During
the fourth quarter, the Company acquired a 198 foot by 40 foot DP vessel (the
MERLIN) purpose built for long term ROV, survey and coring support. The
remaining capital expenditures included the acquisition of two work class ROVs
from Coflexip, the costs associated with installation of a derrick on the UNCLE
JOHN and the cash portion of the fourth quarter natural gas and oil properties
acquisition discussed below. During 1997, the Company had seven vessels out of
service for either regulatory inspection or upgrade programs compared to only
two during 1996.
During the fourth quarter of 1998, the Company sold two offshore natural
gas and oil properties for approximately $600,000 and during the second quarter
of 1997, the Company sold two offshore natural gas and oil properties for
approximately $1.0 million. These transactions were structured as Section 1031
"Like Kind" exchanges for tax purposes. Accordingly, the cash received was
restricted to use for subsequent acquisitions of additional natural gas and oil
properties.
Since 1993, including the transactions closed subsequent to year end, the
Company has invested $28 million to acquire 35 offshore natural gas and oil
leases. The Company records the amount of cash paid together with the
abandonment liability assumed at the time such properties are acquired. Only the
cash paid at closing is reflected in the Company's statement of cash flows
together with bond and escrow deposits required in connection with these
purchases. The Minerals Management Service requires operators in the Gulf of
Mexico to post an areawide bond of $3 million. Beginning in 1998 the MMS allowed
the Company to utilize an insurance carrier to provide such bonding. In
addition, certain of the purchase and sale agreements have required the Company
to fund portions of the estimated decommissioning liability. Accordingly, the
Company's balance sheet as of December 31, 1998 included $2.4 million of cash
deposits restricted for abandonment obligations. In addition, the Company had
also issued letters of credit totaling $26,000 at December 31, 1998 in lieu of
cash deposits in connection with property acquisitions. In January 1999 and
March 1999, the Company acquired, in three separate transactions, interests in
17 blocks (including 94 wells) and assumed the responsibility to decommission
the properties in full compliance with all governmental regulations. The
decommissioning obligations assumed in these transactions were such that a cash
outlay was not required. The Company has had, and anticipates having additional
discussions with third parties regarding possible acquisitions (including
natural gas and oil properties and vessels). However, the Company can give no
assurance that any such transaction can be completed.
FINANCING ACTIVITIES. The Company has financed seasonal operating
requirements and capital expenditures with internally generated funds,
borrowings under credit facilities, and the sale of Common Stock described
above. The Revolving Credit Agreement, as amended, currently provides for a
$40.0 million revolving line of credit. The Revolving Credit Agreement, which
terminates in December 2000, is secured by trade receivables and mortgages on
the Company's vessels. The Revolving Credit Agreement prohibits the payment of
dividends on the Company's capital stock and contains only one financial
covenant (a fixed charge coverage ratio) and a limitation that debt not exceed
$60 million. Interest on borrowings under the Revolving Credit Agreement is
equal to Prime with incentive pricing thereafter pursuant to a formula based
upon EBITDA (as defined therein). No borrowings were outstanding at December 31,
1998. Letters of credit are also available under the Revolving Credit Agreement
which the Company typically uses if performance bonds are required or, in
certain cases, in lieu of purchasing U.S. Treasury Bonds in conjunction with gas
and oil property acquisitions.
The only financing activity in 1998 represents the exercise of stock
options. During the first two quarters of 1997, the Company repaid $5 million,
net of its borrowings under its Revolving Credit Agreement with Fleet Capital
Corporation and in the third quarter repaid the remaining $20 million
outstanding with proceeds from the initial public offering of common stock.
Also, during the second quarter the Company completed a
28
transaction with Coflexip whereby Coflexip agreed to accept treasury shares as
payment for two ROVs added in February.
CAPITAL COMMITMENTS. In connection with its business strategy, management
expects the Company to acquire or build additional vessels, acquire other assets
such as ROVs, as well as seek to buy additional natural gas and oil properties.
The Company has purchased the thrusters and completed engineering for the
conversion of the SEA SORCERESS to full DP, however, this $30 to $35 million
capital expenditure will not be undertaken until commodity prices and market
conditions improve. The Company has also announced that it is considering
building a new Deepwater construction vessel, the Q4000. Depending upon the size
of any future acquisitions, the Company may require additional debt financing,
possibly in excess of the Revolving Credit Agreement, as amended, or additional
equity financing. Other than building, converting or buying DP vessels,
management believes existing cash balances, the net cash generated from
operations and available borrowing capacity under the Revolving Credit Agreement
will be adequate to meet funding requirements for the next year.
YEAR 2000 READINESS DISCLOSURE
The Company has assessed what computer software will require modification
or replacement so that its computer systems will properly utilize dates beyond
December 31, 1999. The Company has purchased, and has implemented, a new project
management accounting system which is Year 2000 compliant. This system, which
fully integrates all of its modules, provides project managers and accounting
personnel with up-to-date information enabling them to better control jobs in
addition to providing benefits in inventory control and planned vessel
maintenance. CDI's vessel computer DP systems are partially dependent on
government satellites and the government has not yet confirmed that they have
solved Year 2000 data problems. If necessary, the vessels could operate for
sometime safely on redundant systems other than satellite information.
Accordingly, the Company believes that the Year 2000 issue will be resolved in
a timely manner and presently does not believe that the cost to become Year 2000
compliant will have a material adverse effect on the Company's consolidated
financial statements. The foregoing statements are intended to be and are
hereby designated "Year 2000 Readiness Disclosure" within the meaning of the
Year 2000 Information Readiness and Disclosure Act.
ITEM 7A. QUANTITIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Not applicable because, at December 31, 1998, the Company was not engaged in any
transactions requiring disclosure under this item.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
Report of Independent Public
Accountants............................................................... 31
Consolidated Balance Sheets -- December 31, 1998 and 1997.................... 32
Consolidated Statements of Operations for the years ended December 31,1998,
1997 and 1996............................................................. 33
29
Consolidated Statements of Shareholders' Equity for the years ended
December 31, 1998, 1997 and 1996.......................................... 34
Consolidated Statements of Cash Flows for the years ended December 31, 1998,
1997 and 1996............................................................. 35
Notes to Consolidated Financial Statements................................... 36
30
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Cal Dive International, Inc.:
We have audited the accompanying consolidated balance sheets of Cal Dive
International, Inc. (a Minnesota corporation), and subsidiaries as of December
31, 1998 and 1997, and the related consolidated statements of operations,
shareholders' equity and cash flows for the three years in the period ended
December 31, 1998. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Cal Dive
International, Inc., and subsidiaries as of December 31, 1998 and 1997, and the
results of their operations and their cash flows for the three years in the
period ended December 31, 1998, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 11, 1999
31
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS -- DECEMBER 31, 1998 AND 1997
(IN THOUSANDS)
DECEMBER 31,
----------------------
1998 1997
--------- ---------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ........................................ $ 32,843 $ 13,025
Accounts receivable --
Trade, net of revenue allowance on gross amounts billed of
$1,335 and $1,822 ..................................... 20,350 23,856
Unbilled revenue .......................................... 10,703 8,134
Other current assets ............................................. 9,190 4,947
--------- ---------
Total current assets ................................... 73,086 49,962
--------- ---------
PROPERTY AND EQUIPMENT ................................................. 107,421 89,499
Less -- Accumulated depreciation ................................. (28,262) (20,021)
--------- ---------
79,159 69,478
--------- ---------
OTHER ASSETS:
Cash deposits restricted for salvage operations .................. 2,408 5,670
Investment in Aquatica, Inc. ..................................... 7,656 --
Other assets, net ................................................ 1,926 490
--------- ---------
$ 164,235 $ 125,600
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable ................................................. $ 15,949 $ 12,919
Accrued liabilities .............................................. 10,020 7,514
Income taxes payable ............................................. 1,201 602
--------- ---------
Total current liabilities .......................... 27,170 21,035
--------- ---------
LONG-TERM DEBT ......................................................... -- --
DEFERRED INCOME TAXES .................................................. 13,539 8,745
DECOMMISSIONING LIABILITIES ............................................ 9,883 6,451
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY:
Common stock, no par, 60,000 shares authorized, 21,402
and 21,345 shares issued and outstanding ...................... 52,981 52,832
Retained earnings ................................................ 64,413 40,288
Treasury stock, 6,820 shares, at cost ............................ (3,751) (3,751)
--------- ---------
Total shareholders' equity ............................. 113,643 89,369
--------- ---------
$ 164,235 $ 125,600
========= =========
The accompanying notes are an integral part of these consolidated
financial statements.
32
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
1998 1997 1996
--------- --------- ---------
NET REVENUES:
Subsea and salvage ..................................... $ 139,310 $ 92,860 $ 63,870
Natural gas and oil production ......................... 12,577 16,526 12,252
--------- --------- ---------
151,887 109,386 76,122
COST OF SALES:
Subsea and salvage ..................................... 93,607 67,538 46,766
Natural gas and oil production ......................... 9,071 8,163 7,270
--------- --------- ---------
Gross profit ...................................... 49,209 33,685 22,086
--------- --------- ---------
SELLING AND ADMINISTRATIVE EXPENSES:
Selling expenses ....................................... 1,224 1,429 1,157
Administrative expenses ................................ 14,577 9,767 7,134
--------- --------- ---------
Total selling and administrative expenses . 15,801 11,196 8,291
--------- --------- ---------
INCOME FROM OPERATIONS ....................................... 33,408 22,489 13,795
Equity in earnings of Aquatica, Inc. ................... 2,633 -- --
Net interest (income) expense and other ................ (1,103) 208 781
--------- --------- ---------
INCOME BEFORE INCOME TAXES ................................... 37,144 22,281 13,014
Provision for income taxes ............................. 13,019 7,799 4,579
--------- --------- ---------
NET INCOME ................................................... $ 24,125 $ 14,482 $ 8,435
========= ========= =========
NET INCOME PER SHARE:
Basic .................................................. $ 1.66 $ 1.12 $ 0.76
Diluted ................................................ 1.61 1.09 0.75
========= ========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING:
Basic .................................................. 14,549 12,883 11,099
Diluted ................................................ 14,964 13,313 11,286
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
33
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(IN THOUSANDS)
COMMON STOCK TREASURY STOCK TOTAL
--------------------- RETAINED ----------------------- SHAREHOLDERS'
SHARES AMOUNT EARNINGS SHARES AMOUNT EQUITY
------- -------- -------- -------- -------- --------
BALANCE, DECEMBER 31, 1995 ............... 18,448 $ 9,093 $ 17,371 (7,349) $ (4,055) $ 22,409
NET INCOME ............................... -- -- 8,435 -- -- 8,435
------- -------- -------- -------- -------- --------
BALANCE, DECEMBER 31, 1996 ............... 18,448 9,093 25,806 (7,349) (4,055) 30,844
NET INCOME ............................... -- -- 14,482 -- -- 14,482
ACTIVITY IN COMPANY STOCK PLANS .......... 22 327 -- -- -- 327
SALE OF TREASURY STOCK, NET .............. -- 4,055 -- 529 304 4,359
SALE OF COMMON STOCK, NET ................ 2,875 39,357 -- -- -- 39,357
------- -------- -------- -------- -------- --------
BALANCE, DECEMBER 31, 1997 ............... 21,345 52,832 40,288 (6,820) (3,751) 89,369
NET INCOME ............................... -- -- 24,125 -- -- 24,125
ACTIVITY IN COMPANY STOCK PLANS, NET ..... 57 149 -- -- -- 149
------- -------- -------- -------- -------- --------
BALANCE, DECEMBER 31, 1998 ............... 21,402 $ 52,981 $ 64,413 (6,820) $ (3,751) $113,643
======= ======== ======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
34
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1998 1997 1996
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................. $ 24,125 $ 14,482 $ 8,435
Adjustments to reconcile net income to net cash provided by
operating activities --
Depreciation and amortization .......................... 9,563 7,512 5,257
Deferred income taxes .................................. 4,469 3,789 2,122
Equity in Earnings of Aquatica, Inc. ................... (2,633) -- --
Gain on sale of property ............................... (585) (464) --
Changes in operating assets and liabilities:
Accounts receivable, net ............................... 937 (5,777) (15,287)
Other current assets ................................... (3,919) (2,653) (299)
Accounts payable and accrued liabilities ............... 5,536 4,766 6,355
Income taxes payable, net .............................. 599 736 280
Other noncurrent, net .................................. (2,395) (97) 782
-------- -------- --------
Net cash provided by operating activities ........... 35,697 22,294 7,645
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ........................................ (14,886) (28,936) (27,289)
Investment in Aquatica, Inc. ................................ (5,023) -- --
Deposits restricted for salvage operations .................. 3,262 (436) (255)
Proceeds from sale of property .............................. 619 1,084 244
-------- -------- --------
Net cash used in investing activities ............... (16,028) (28,288) (27,300)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock, net of transaction costs .............. -- 39,357 --
Sale of treasury stock, net of transaction costs ............ -- 4,359 --
Borrowings under term loan facility ......................... -- 6,700 25,000
Exercise of stock warrants and options, net ................. 149 99 --
Repayments of long-term debt ................................ -- (31,700) (5,300)
-------- -------- --------
Net cash provided by financing activities ........... 149 18,815 19,700
-------- -------- --------
NET INCREASE IN CASH AND CASH EQUIVALENTS ...................... 19,818 12,821 45
CASH AND CASH EQUIVALENTS:
Balance, beginning of year .................................. 13,025 204 159
-------- -------- --------
Balance, end of year ........................................ $ 32,843 $ 13,025 $ 204
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
35
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION:
Cal Dive International, Inc. (Cal Dive, CDI or the Company), headquartered
in Houston, Texas, owns, staffs and operates ten marine construction vessels and
a derrick barge in the Gulf of Mexico. The Company provides a full range of
services to offshore oil and gas exploration and production and pipeline
companies, including underwater construction, maintenance and repair of
pipelines and platforms, and salvage operations.
In September 1992, Cal Dive formed a wholly owned subsidiary, Energy
Resource Technology, Inc. (ERT), to purchase producing offshore oil and gas
properties which are in the later stages of their economic lives. ERT is a fully
bonded offshore operator and, in conjunction with the acquisition of properties,
assumes the responsibility to decommission the property in full compliance with
all governmental regulations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of
the Company and its subsidiaries. All significant intercompany accounts and
transactions have been eliminated.
INVESTMENT IN AQUATICA, INC.
In February 1998, the Company purchased a significant minority stake in
Aquatica, Inc. ("Aquatica") for $5 million, in addition to a commitment to lend
additional funds (up to $5 million) to allow Aquatica to purchase vessels and
fund other growth opportunities. Aquatica, headquartered in Lafayette,
Louisiana, is a surface diving company founded in October 1997 with the
acquisition of Acadiana Divers, a 15 year old surface diving company. Dependent
upon various preconditions, as defined, the shareholders of Aquatica have the
right to convert their shares into Cal Dive shares at a ratio based on a formula
which, among other things, values their interest in Aquatica and must be
accretive to Cal Dive shareholders. The Company accounts for this investment on
the equity basis of accounting for financial reporting purposes.
PROPERTY AND EQUIPMENT
Property and equipment are recorded at cost. Depreciation is provided
primarily on the straight-line method over the estimated useful lives of the
assets.
All of the Company's interests in natural gas and oil properties are
located offshore in United States waters. The Company follows the successful
efforts method of accounting for its interests in natural gas and oil
properties. Under the successful efforts method, only the costs of successful
wells and leases containing productive reserves are capitalized.
ERT offshore property acquisitions are recorded at the value exchanged at
closing together with an estimate of its proportionate share of the
decommissioning liability assumed in the purchase based upon its working
interest ownership percentage. In estimating the decommissioning liability to be
assumed in offshore property acquisitions, the Company performs very 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.
36
The following is a summary of the components of property and equipment
(dollars in thousands):
ESTIMATED
USEFUL LIFE 1998 1997
----------- ---- ----
Vessels ........................................... 15 $ 72,220 $ 62,814
Offshore leases and equipment ..................... UOP 22,530 15,634
Machinery and equipment ........................... 5 9,195 8,191
Leasehold improvements, furniture, software and
computer equipment ............................ 5 3,194 2,651
Automobiles and trucks ............................ 3 282 209
-------- --------
Total property and equipment ................ $107,421 $ 89,499
======== ========
The cost of repairs and maintenance of vessels and equipment is charged to
operations as incurred, while the cost of improvements is capitalized. Total
repair and maintenance charges were $8,264,000, $6,771,000 and $3,655,000 for
the years ended December 31, 1998, 1997 and 1996, respectively. Upon the
disposition of property and equipment, the related cost and accumulated
depreciation accounts are relieved, and the resulting gain or loss is included
in other income (expense).
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
DEFERRED DRYDOCK CHARGES
Effective January 1, 1998, the Company changed its method of accounting
for regulatory (U.S. Coast Guard, American Bureau of Shipping and Det Norske
Veritas) related drydock inspection and certification expenditures. This change
was made due to the significant changes in the composition of the Company's
fleet which has been expanded to include more sophisticated dynamically
positioned vessels that are capable of working in the Deepwater Gulf of Mexico,
a key to Cal Dive's operating strategy. The change also coincides with the first
time these vessels were due for drydock inspection and certification since being
acquired by CDI. The Company previously expensed inspection and certification
costs as incurred; however, effective January 1, 1998, such expenditures are
being capitalized and amortized over the 30-month period between regulatory
mandated drydock inspections and certification. This predominant industry
practice provides better matching of expenses with the period benefited (i.e.,
certification to operate the vessel for a 30-month period between required
drydock inspections and to meet bonding and insurance coverage requirements).
This change had a $765,000 positive impact on net income, or $0.05 per share, in
the Company's 1998 consolidated financial statements. The cumulative effect of
this change in accounting principle is immaterial to the Company's consolidated
financial statements taken as a whole.
REVENUE RECOGNITION
The Company earns the majority of its service revenues during the summer
and fall months. Revenues are derived from billings under contracts (which are
typically of short duration) that provide for either lump-sum turnkey charges or
specific time, material and equipment charges which are billed in accordance
with the terms of such contracts. The Company recognizes revenue as it is earned
at estimated collectible amounts. Revenue on significant turnkey contracts is
recognized on the percentage-of-completion method based on the ratio of
37
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, 1998 are expected to be billed and collected
within one year.
REVENUE ALLOWANCE ON GROSS AMOUNTS BILLED
The Company bills for work performed in accordance with the terms of the
applicable contract. The gross amount of revenue billed will include not only
the billing for the original amount quoted for a project but also include
billings for services provided which the Company believes are outside the scope
of the original quote. The Company establishes a revenue allowance for these
additional billings based on its collections history if conditions warrant such
a reserve.
MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK
The market for the Company's services is the offshore oil and gas
industry. Oil and gas companies make capital expenditures on exploration,
drilling and production operations offshore, the level of which is generally
dependent on the prevailing view of the future oil and gas prices, which have
been characterized by significant volatility in recent years as commodity prices
declined significantly in the second half of 1998. Although the level of
activity with respect to the Company's services has not experienced a
significant decline, there can be no assurance that such levels will be
maintained should a sustained period of low oil and gas prices persist.
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; however, such losses have historically
been insignificant.
Chevron USA, Inc. accounted for 11% of consolidated revenues in 1998. J.
Ray McDermott, S.A. accounted for 19% and 24% of consolidated revenues in the
years 1997 and 1996, respectively. In addition, Shell Oil Co. accounted for 11%
of consolidated revenues in 1997.
INCOME TAXES
Deferred taxes are recognized for revenues and expenses reported in
different years for financial statement purposes and income tax purposes in
accordance with SFAS No. 109, "Accounting for Income Taxes." The statement
requires, among other things, the use of the liability method of computing
deferred income taxes. The liability method is based on the amount of current
and future taxes payable using tax rates and laws in effect at the balance sheet
date.
EARNINGS PER SHARE
The Company computes and presents earning per share in accordance with
Statement of Financial Accounting Standard No. 128, "Earnings Per Share". SFAS
128 requires the presentation of "basic" EPS and "diluted" EPS on the face of
the statement of operations. Basic EPS is computed by dividing the net income
available to common shareholders by the weighted-average shares of outstanding
common stock. The calculation of diluted EPS is similar to basic EPS except that
the denominator includes dilutive common stock equivalents, which were stock
options, less the number of treasury shares assumed to be purchased from the
38
proceeds from the exercise of stock options.
STATEMENT OF CASH FLOW INFORMATION
The Company defines cash and cash equivalents as cash and all highly
liquid financial instruments with original maturities of less than three months.
During the years ended December 31, 1998, 1997 and 1996, the Company's cash
payments for interest were approximately $-0-, $1,033,000 and $1,069,000
respectively, and cash payments for federal income taxes were approximately
$7,650,000, $3,200,000 and $2,200,000, 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.
RESTRICTED CASH DEPOSITS
The Company follows SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities." Under SFAS No. 115, debt securities, including
treasury bills and notes, that the Company has both the intent and ability to
hold to maturity, are carried at amortized cost and are included in cash
deposits restricted for salvage operations in the accompanying consolidated
balance sheets. As all of these securities as of December 31, 1998, are U.S.
Treasury securities and notes, the majority of which mature beyond one year, the
Company believes the recorded balance of these securities approximates their
fair market value.
3. OFFSHORE PROPERTY ACQUISITIONS:
During 1996, net working interests of 33 percent to 100 percent in four
offshore blocks were acquired in exchange for cash of $3,609,000 and ERT
assuming the related abandonment liabilities. During 1997, ERT acquired net
working interests of 50 percent to 100 percent in 3 offshore blocks in exchange
for $1.3 million in cash and assumption of a pro rata share of the
decommissioning liability and in 1998, ERT acquired interest in six blocks
involving two separate fields (a 55% interest in East Cameron 231 and a 18%
interest in East Cameron 353) in exchange for cash of $1,000,000 as well as
assumption of the pro rata share of the related decommissioning liability. In
connection with 1998, 1997 and 1996 offshore property acquisitions, ERT assumed
net abandonment liabilities estimated at approximately $3,432,000, $1,351,000
and $1,200,000, respectively.
ERT production activities are regulated by the federal government and
require significant third-party involvement, such as refinery processing and
pipeline transportation. The Company records revenue from its offshore
properties net of royalties paid to the Minerals Management Service ("MMS").
Royalty fees paid totaled approximately $2,031,000, $3,018,000 and $1,996,000
for the years ended 1998, 1997 and 1996, respectively. In accordance with
federal regulations that require operators in the Gulf of Mexico to post an
areawide bond of $3,000,000, cash deposits restricted for salvage operations
included U.S. Treasury bonds of $3,300,000 at December 31, 1997 (see Note 2). In
1998, the MMS allowed the Company to release the U.S. Treasury Bonds in favor of
bonding through an insurance carrier. In addition, the terms of certain of the
1993 purchase and sale agreements require that ERT deposit a portion of a
property's net production revenue into interest-bearing escrow accounts until
such time as a specified level of funding has been set aside for salvaging and
abandoning the properties. As of December 31, 1998, such deposits totaled
$2,408,000 and are included in cash deposits restricted for salvage operations
in the accompanying consolidated balance sheet.
4. ACCRUED LIABILITIES:
39
Accrued liabilities consisted of the following (in thousands):
1998 1997
------- -------
Accrued payroll and related benefits ................. $ 5,198 $ 4,097
Workers compensation claims .......................... 1,919 1,100
Workers compensation claims to be reimbursed ......... 867 1,568
Other ................................................ 2,036 749
------- -------
Total accrued liabilities ...................... $10,020 $ 7,514
======= =======
5. REVOLVING CREDIT FACILITY:
During 1995, the Company entered into a $30 million revolving credit
facility secured by property and equipment and trade receivables. At the
Company's option, interest was at a rate equal to 2.00 percent above a
Eurodollar base rate (2.25 on borrowings less than $10 million) or .5 percent
above prime. The Company drew upon the revolving credit facility during 1997 and
1996. Under this credit facility, letters of credit (LOC) are also available
which the Company typically uses if performance bonds are required and, in
certain cases, in lieu of purchasing U.S. Treasury bonds in conjunction with ERT
property acquisitions. At December 31, 1998 and 1997, LOC totaling $26,000
million and $2.92 million were outstanding pursuant to these terms.
During April 1997, the revolving credit facility was amended, increasing
the amount available to $40 million, reducing the financial covenant
restrictions to one (a fixed charge ratio) and reducing the interest rate from
.5% above prime and 2% above the Eurodollar base rate to prime and 1.25 to 2.50
percent above Eurodollar based on specific provisions set forth in the loan
agreement. The Company was in compliance with these debt covenants at December
31, 1998.
6. FEDERAL INCOME TAXES:
Federal income taxes have been provided based on the statutory rate of 34
percent in 1996 and 35 percent in 1997 and 1998 adjusted for items which are
allowed as deductions for federal income tax reporting purposes, but not for
book purposes. The primary differences between the statutory rate and the
Company's effective rate are as follows:
1998 1997 1996
---- ---- ----
Statutory rate .................................. 35% 35% 34%
Research and development tax credits ............ (1) -- --
Other ........................................... 1 -- 1
---- ---- ----
Effective rate ............................ 35% 35% 35%
=== === ===
Components of the provision for income taxes reflected in the statements
of operations consist of the following (in thousands):
1998 1997 1996
------- ------- -------
Current ..................... $ 8,550 $ 4,010 $ 2,457
Deferred .................... 4,469 3,789 2,122
------- ------- -------
$13,019 $ 7,799 $ 4,579
======= ======= =======
40
Deferred income taxes result from those transactions which affect
financial and taxable income in different years. The nature of these
transactions and the income tax effect of each as of December 31, 1998 and 1997,
is as follows (in thousands):
1998 1997
-------- --------
Deferred tax liabilities --
Depreciation ............................... $ 13,539 $ 8,745
Deferred tax assets --
Reserves, accrued liabilities and other .. (416) (91)
-------- --------
Net deferred tax liability ......... $ 13,123 $ 8,654
======== ========
7. COMMITMENTS AND CONTINGENCIES:
LEASE COMMITMENTS
The Company occupies several facilities under noncancelable operating
leases, with the more significant leases expiring in the years 2004 and 2007.
Future minimum rentals under these leases are $4.1 million at December 31, 1998
with $599,000 due in 1999, $590,000 in 2000, $607,000 in 2001, $631,000 in 2002,
$683,000 in 2003 and the balance thereafter. Total rental expense under
operating leases was $601,000, $376,000 and $262,000 for the years ended
December 31, 1998, 1997 and 1996, respectively.
INSURANCE AND LITIGATION
The Company carries hull protection on vessels, indemnity insurance and a
general umbrella policy. All onshore employees are covered by workers'
compensation, and all offshore employees, including divers and tenders, are
covered by Jones Act employee coverage, the maritime equivalent of workers'
compensation. The Company is exposed to deductible limits on its insurance
policies, which vary from $5,000 to a maximum of $100,000 per accident
occurrence. Effective August 1, 1992, the Company adopted a self-insured (within
specified limits) medical and health benefits program for its employees whereby
the Company is exposed to a maximum of $15,000 per claim.
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
$867,000 and $1,568,000 as of December 31, 1998 and 1997, respectively. See
related accrued liabilities at Note 4. The Company has not incurred any
significant losses as a result of claims denied by its insurance carriers. In
addition, the Company from time to time incurs other claims, such as contract
disputes, in the normal course of business. In the opinion of management, the
ultimate liability to the Company, if any, which may result from the claims
discussed above will not materially affect the Company's consolidated financial
position, results of operations or net cash flows.
SALVAGE ALLIANCE
Through an alliance with Horizon Offshore the Company has access to
expanded derrick barge and pipelay capacity. In this regard Cal Dive has
guaranteed a certain level of barge activity which it expects to use in
conjunction with CDI salvage operations.
8. EMPLOYEE BENEFIT PLANS:
41
DEFINED CONTRIBUTION PLAN
The Company sponsors a defined contribution 401(k) retirement plan
covering substantially all of its employees. The Company's contributions and
cost are determined annually as 50 percent of each employee's contribution up to
5 percent of the employee's salary. The Company's costs related to this plan
totaled $466,000, $270,000 and $197,000 for the years ended December 31, 1998,
1997 and 1996, respectively.
STOCK-BASED COMPENSATION PLANS
During 1995, the board of directors and shareholders approved the 1995
Long-Term Incentive Plan (the Incentive Plan). Under the Incentive Plan, a
maximum of 10% of the total shares of Common Stock issued and outstanding may be
granted to key executives and selected employees who are likely to make a
significant positive impact on the reported net income of the Company. The
Incentive Plan is administered by a committee which determines, subject to
approval of the Compensation Committee of the Board of Directors, the type of
award to be made to each participant and sets forth in the related award
agreement the terms, conditions and limitations applicable to each award. The
committee may grant stock options, stock appreciation rights, or stock and cash
awards. Options granted to employees under the Incentive Plan vest 20% per year
for a five year period, have a maximum exercise life of five years and, subject
to certain exceptions, are not transferable.
Effective May 12, 1998, the Company adopted a qualified, non-compensatory
Employee Stock Purchase Plan ("ESPP"), which allows employees to acquire shares
of common stock through payroll deductions over a six month period. The purchase
price is equal to 85 percent of the fair market value of the common stock on
either the first or last day of the subscription period, whichever is lower.
Purchases under the plan are limited to 10 percent of an employee's base salary.
Under this plan 13,937 shares of common stock were purchased in the open market
at a weighted average share price of $21.25 during 1998.
The Incentive Plan and ESPP are accounted for using APB Opinion No. 25,
and therefore no compensation expense is recorded. If SFAS Statement No. 123 had
been used for the accounting of these plans, the Company's pro forma net income
for 1998, 1997 and 1996 would have been $23,735,000, $14,023,000 and $8,330,000,
respectively, and the Company's pro forma diluted earnings per share would have
been $1.59, $1.07 and $0.74, respectively. These pro forma results exclude
consideration of options granted prior to January 1, 1995, and therefore may not
be representative of that to be expected in future years.
All of the options outstanding at December 31, 1998, have exercise prices
as follows: 378,750 shares at $4.50, 445,000 shares at $9.50, 95,000 shares at
$13.00 and 125,850 shares from $20.56 to $23.25 and a weighted average remaining
contractual life of 3.48 years.
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option pricing model with the following weighted average
assumptions used for grants in 1995 and 1996: risk-free interest rates of 5.9
percent; expected dividend yields of 0 percent; expected lives of five years;
and expected volatility of 0 percent as the Company was a privately held entity
and accordingly estimating the expected volatility was not feasible. The same
weighted average assumptions were used for grants in 1997 and 1998 with the
exception of risk-free interest rate assumed to be 5.5 percent in 1997 and 5.0
percent in 1998 and expected volatility to be 36 percent in 1997 and 59 percent
in 1998. The fair value of shares issued under the ESPP was based on the 15%
discount received by the employees.
Options outstanding are as follows:
42
1998 1997 1996
---- ---- ----
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
---------- ------ ------- ------ ------- ------
Options outstanding, beginning of
year ........................... 994,500 $ 8.66 544,500 $ 4.50 447,500 $ 4.50
Granted .......................... 325,850 23.55 540,000 12.17 135,000 4.50
Exercised ........................ (56,750) 5.03 (22,000) 4.50 -- --
Terminated ....................... (219,000) 28.24 (68,000) 4.50 (38,000) 4.50
---------- ------ ------- ------ ------- ------
Options outstanding,
December 31 .................... 1,044,600 $ 9.40 994,500 $ 8.66 544,500 $ 4.50
Options exercisable,
December 31 .................... 222,950 $ 6.50 199,604 $ 4.50 124,700 $ 4.50
========== ====== ======= ====== ======= ======
Options granted and options terminated under the Incentive Plan for 1998
include options which were repriced on November 6, 1998. The options which were
repriced were originally granted between August 25, 1997 and May 11, 1998 with
original exercise prices between $28.38 and $37.25. Options for 165,000 shares
were cancelled on November 6, 1998 and a proportionately reduced number of
shares (100,850) were reissued at an exercise price of $20.56 per share with a
new five year vesting period.
9. COMMON STOCK:
The Company's amended and restated Articles of Incorporation provide for
authorized Common Stock of 60,000,000 shares with no par value per share.
On April 11, 1997, Coflexip purchased approximately 3,700,000 shares of
the Company's stock, consisting of approximately 2.1 million shares sold by
management of the Company, 1.1 million shares sold by First Reserve Funds and
approximately 500,000 shares sold by the Company at a price of $9.46 per share.
The Company had previously, in February of 1997, contracted with Coflexip to
acquire two ROVs at published retail prices. Coflexip agreed to accept
approximately 500,000 shares of the Company's Common Stock as payment for the
ROVs and as part of the transaction described above.
In conjunction with this transaction, the Company entered into a new
Shareholders Agreement. The new Shareholders Agreement provides that, except in
limited circumstances (including issuance of securities under stock option plans
or in conjunction with acquisitions), the Company shall provide preemptive
rights to acquire the Company's securities to each of Coflexip, First Reserve
and the Executive Directors. The Shareholders Agreement also provides that the
Company will not enter into an agreement (i) to sell the Company, (ii) to retain
an advisor to sell the Company or (iii) to pursue any acquisition in excess of
50% of the Company's market capitalization without first notifying Coflexip in
writing and providing Coflexip the opportunity to consummate an acquisition on
terms substantially equivalent to any proposal.
The Company completed an initial public offering of common stock on July
7, 1997, with the sale of 4.1 million shares at $15 per share. Of the 4.1
million shares, 2,875,000 shares were sold by the Company and 1,265,000 shares
were sold by First Reserve Funds. Net proceeds to the Company of approximately
$39.4 million were used to retire all of its then outstanding long-term
indebtedness of $20 million.
In May 1998, the Company completed a secondary offering of 2,867,070
shares of common stock at $33.50 per share on behalf of certain selling
shareholders. The Company received no proceeds from the offering.
10. BUSINESS SEGMENT INFORMATION (IN THOUSANDS):
43
The following summarizes certain financial data by business segment:
YEAR ENDED DECEMBER 31,
1998 1997 1996
--------- --------- ---------
Revenues --
Subsea and salvage ................................ $ 139,310 $ 92,860 $ 63,870
Natural gas and oil production .................... 12,577 16,526 12,252
--------- --------- ---------
Total ..................................... $ 151,887 $ 109,386 $ 76,122
========= ========= =========
Income from operations --
Subsea and salvage ................................ $ 31,440 $ 16,411 $ 10,503
Natural gas and oil production .................... 1,968 6,078 3,292
--------- --------- ---------
Total ..................................... $ 33,408 $ 22,489 $ 13,795
========= ========= =========
Net interest (income) expense and other -
Subsea and salvage ................................ $ (705) $ 379 $ 742
Natural gas and oil production .................... (398) (171) 39
--------- --------- ---------
Total ..................................... $ (1,103) $ 208 $ 781
========= ========= =========
Provision for income taxes -
Subsea and salvage ................................ $ 12,195 $ 5,614 $ 3,440
Natural gas and oil production .................... 824 2,185 1,139
--------- --------- ---------
Total ..................................... $ 13,019 $ 7,799 $ 4,579
========= ========= =========
Identifiable assets --
Subsea and salvage ................................ $ 142,629 $ 107,420 $ 63,217
Natural gas and oil production .................... 21,606 18,180 19,839
--------- --------- ---------
Total ..................................... $ 164,235 $ 125,600 $ 83,056
========= ========= =========
Capital expenditures --
Subsea and salvage ................................ $ 10,923 $ 26,984 $ 20,038
Natural gas and oil production .................... 3,963 1,952 7,251
--------- --------- ---------
Total ..................................... $ 14,886 $ 28,936 $ 27,289
========= ========= =========
Depreciation and amortization --
Subsea and salvage ................................ $ 6,966 $ 4,000 $ 2,525
Natural gas and oil production .................... 2,597 3,512 2,732
--------- --------- ---------
Total ..................................... $ 9,563 $ 7,512 $ 5,257
========= ========= =========
11. 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,
1998 1997
-------- --------
Proved properties being amortized ........................... $ 22,530 $ 15,634
Less -- Accumulated depletion, depreciation and amortization (9,082) (6,845)
-------- --------
Net capitalized costs ................................. $ 13,448 $ 8,789
======== ========
Included in capitalized costs is the Company's estimate of its
proportionate share of decommissioning liabilities assumed relating to these
properties. As of December 31, 1998 and 1997, such liabilities totaled $9.9
million and $6.5 million, respectively, and are also reflected as
decommissioning liabilities in the accompanying consolidated balance sheet.
44
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
The following table reflects the costs incurred in oil and gas property
acquisition and development activities during the dates indicated:
YEAR ENDED DECEMBER 31,
1998 1997 1996
------- ------ ------
Proved property acquisition costs......... $ 5,416 $2,687 $4,688
Development costs......................... 2,281 385 2,048
------- ------ ------
Total costs incurred................ $ 7,697 $3,072 $6,736
======= ====== ======
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
YEAR ENDED DECEMBER 31,
1998 1997 1996
------- ------- -------
Revenues ......................................... $12,577 $16,526 $12,252
Production (lifting) costs ....................... 6,820 4,651 4,538
Depreciation, depletion and amortization ......... 2,597 3,512 2,732
------- ------- -------
Pretax income from producing activities .......... 3,160 8,363 4,982
Income tax expenses .............................. 1,106 2,927 1,744
------- ------- -------
Results of oil and gas producing activities ...... $ 2,054 $ 5,436 $ 3,238
======= ======= =======
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,
1998, have been reviewed by Miller and Lents, Ltd., independent petroleum
engineers. All of the Company's reserves are located in the United States.
Proved reserves cannot 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, 1995, all of the Company's proved reserves were
developed. As of December 31, 1996 and 1997, 4,500 Bbls. of oil and 6,325,700
Mcf. of gas of the Company's proved reserves were undeveloped. As of December
31, 1998, 400 Bbls. of oil and 1,153,300 Mcf. of gas were undeveloped.
OIL GAS
RESERVE QUANTITY INFORMATION (BBLS.) (MCF.)
------- -------
Total proved reserves at December 31, 1995 ........ 122 20,398
Revisions of previous estimates .............. 32 (365)
Production ................................... (38) (4,310)
Purchases of reserves in place ............... 8 8,873
------- -------
Total proved reserves at December 31, 1996 ......... 124 24,596
Revisions of previous estimates .............. (21) 1,831
Production ................................... (51) (5,385)
Purchases of reserves in place ............... 149 2,115
Sales of reserves in place ................... (1) (912)
------- -------
Total proved reserves at December 31, 1997 ......... 200 22,245
Revisions of previous estimates ........ (123) (1,706)
Production ................................... (67) (4,535)
Purchase of reserves in place................. 60 6,631
Sales of reserves in place.................... - ( 201)
------- -------
Total proved reserves at December 31, 1998 70 22,434
======= =======
45
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:
1998 1997 1996
-------- -------- --------
Future cash inflows ......................... $ 47,691 $ 59,819 $ 92,393
Future costs --
Production .......................... (17,412) (23,675) (26,247)
Development and abandonment ......... (11,232) (6,917) (7,365)
-------- -------- --------
Future net cash flows before income taxes ... 19,047 29,227 58,781
Future income taxes ................... (6,477) (7,927) (17,980)
-------- -------- --------
Future net cash flows ....................... 12,570 21,300 40,801
Discount at 10% annual rate ........... (2,414) (1,540) (6,996)
-------- -------- --------
Standardized measure of discounted future net
cash flows .............................. $ 10,156 $ 19,760 $ 33,805
======== ======== ========
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:
1998 1997 1996
-------- -------- --------
Standardized measure, beginning of year ........ $ 19,760 $ 33,805 $ 7,645
Sales, net of production costs ................. (5,757) (11,441) (9,882)
Net change in prices, net of production costs .. (4,573) (17,707) 22,201
Changes in future development costs ............ (1,736) 160 (555)
Development costs incurred ..................... 2,281 385 2,007
Accretion of discount .......................... 2,711 4,870 1,200
Net change in income taxes ..................... 2,120 7,544 (10,539)
Purchases of reserves in place ................. 4,403 3,282 21,730
Sales of reserves in place ..................... (57) (2,480) --
Net change due to revision in quantity estimates (3,192) 2,289 (150)
Changes in production rates (timing) and other . (5,804) (947) 148
-------- -------- --------
Standardized measure, end of year .............. $ 10,156 $ 19,760 $ 33,805
======== ======== ========
12. 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, 1998 (in thousands):
1998 1997 1996
------- ------- -------
Beginning balance .............. $ 1,822 $ 1,021 $ 402
Additions ...................... 2,998 3,058 1,784
Deductions ..................... (3,485) (2,257) (1,165)
------- ------- -------
Ending balance ................. $ 1,335 $ 1,822 $ 1,021
======= ======= =======
See Note 2 for a detailed discussion regarding the Company's accounting
policy on the revenue allowance on gross amounts billed.
46
13. 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 1998 and 1997.
QUARTER ENDED
-------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Fiscal 1998
Revenues .................... $33,157 $38,526 $42,913 $ 37,291
Gross profit ................ 10,563 12,134 15,116
11,395
Net income .................. 5,243 5,954 7,577 5,351
Net income per share:
Basic .................. 0.36 0.41 0.52 0.37
Diluted ................ 0.35 0.40 0.51 0.36
Fiscal 1997
Revenues .................... $18,444 $28,628 $28,859 $ 33,455
Gross profit ................ 5,423 9,282 8,419 10,561
Net income .................. 1,886 4,604 3,983 4,009
Net income per share:
Basic .................. 0.17 0.40 0.28 0.28
Diluted ................ 0.17 0.39 0.27 0.27
14. SUBSEQUENT EVENTS (UNAUDITED):
ACQUISITION OF OFFSHORE BLOCKS
In January 1999, ERT acquired interests in ten blocks involving seven
separate fields from Sonat Exploration Company. The properties were purchased in
exchange for cash consideration, as well as assumption of Sonat's pro rata share
of the related decommissioning liability. In addition, in March 1999, ERT
acquired five offshore blocks from Shell Offshore, Inc. and two blocks from
Vastar Resources, Inc. in exchange for cash consideration, as well as assumption
of Shell's and Vastar's pro rata shares of the related decommissioning
liabilities. The decommissioning obligations of $16.1 million assumed in these
three transactions were such that a cash outlay was not required in conjunction
with the property acquisition.
47
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this Item is incorporated by reference to the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A
under the Securities Act of 1934 in connection with the Company's 1999 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 1999 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 1999 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 1999 Annual
Meeting of Shareholders.
48
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(1) Financial Statements.
The following financial statements included on pages 31 through 47 in this
Annual Report are for the fiscal year ended December 31, 1998.
Independent Auditors' Report.
Consolidated Balance Sheets as of December 31, 1998 and 1997.
Consolidated Statements of Operations for the Years Ended December 31,
1998, 1997 and 1996.
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 1998, 1997 and 1996.
Consolidated Statements of Cash Flows for the Years Ended December 31,
1998, 1997 and 1996.
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 of Form 8-K.
None.
(c) 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:
EXHIBIT
NUMBER
* 2.1 -- Purchase Agreement among the Company, Aquatica, Inc. and
Prentiss A. Freeman dated January 27, 1998
.
3.1 -- Amended and Restated Articles of Incorporation of Registrant,
incorporated by reference to Exhibit 3.1 to the Form S-1
Registration Statement filed by the Company on May 1, 1997 (Reg.
No 333-26357).
3.2 -- Bylaws of Registrant, incorporated by reference to Exhibit 3.2
to the Form S-1 Registration Statement filed by the Company on
May 1, 1997 (Reg. No.
333-26357).
4. 1 -- Amended and Restated Loan and Security Agreement by and among
the Company, ERT
49
and Fleet Capital Corporation (f/n/a Shawmut Capital Corporation)
dated as of May 23, 1995, incorporated by reference to Exhibit
4.1 to the Form S-1 Registration Statement filed by the
Registrant on May 1, 1997 (Reg. No. 333-26357).
4.2 -- Amendment No. 5 to Loan, incorporated by reference to Exhibit
4.2 to the Form S-1 Registration Statement filed by the Company
on May 1, 1997(Reg.
No. 333-26357).
4.3 -- Form of Common Stock certificate, incorporated by reference to
Exhibit 4.1 to the Form S-1 filed by the Company on May 1, 1997
(Reg. No. 333-26357).
4.4 -- Shareholders Agreement by and among the Company, First Reserve
Secured Energy Asset Fund, First Reserve Fund V, First Reserve
Fund V-2, First Reserve Fund (collectively the "Selling
Shareholders"), Messrs. Reuhl, Kratz, Nelson and other
shareholders of the Company incorporated by reference to Exhibit
4.4 to the Form S-1 Registration Statement filed by the Company
on May 1, 1997 (Reg. No. 333-26357).
4.5 -- Registration Rights Agreement by and between the Company, the
Selling Shareholders,Messrs. Reuhl, Kratz, Nelson and other
shareholders of the Company incorporated by reference to Exhibit
4.5 to the Form S-1 Registration Statement filed by the Company
on May 1, 1997 (Reg. No. 333-26357).
4.6 -- Registration Rights Agreement by and between the Company and
Coflexip incorporated by reference to Exhibit 4.6 to the Form S-1
Registration Statement filed by the Company on May 1, 1997 (Reg.
No. 333-26357).
4.7 -- First Amended and Restated 1995 Registration Rights Agreement
dated as of April 11, 1997, among the Company, First Reserve
Secured Energy Assets Fund, Limited Partnership, First Reserve
Fund V, Limited Partnership, First Reserve Fund V-2, Limited
Partnership, First Reserve Fund VI, Limited Partnership, Gerald
G. Reuhl, Owen Kratz and S. James Nelson, incorporated by
reference to Exhibit 4.7 to the Form S-1 Registration Statement
filed by the Company on April 22, 1998 (Reg. No. 333-50751)
10.1 -- Purchase Agreement dated April 11, 1997 by and between
Coflexip and the Company incorporated by reference to Exhibit
10.1 to the Form S-1 Registration Statement filed by Company on
May 1, 1997 (Reg. No. 333-26357).
10.2 -- Business Cooperation Agreement dated April 11, 1997 by and
between Coflexip and the Company incorporated by reference to
Exhibit 10.2 to the Form S-1 Registration Statement filed by the
Company on May 1, 1997 (Reg. No. 333-26357).
+10.3 -- 1995 Long Term Incentive Plan, as amended incorporated by
reference to Exhibit 10.3 to the Form S-1 Registration Statement
filed by Company on May 1, 1997 (Reg. No. 333-26357).
+*10.5 -- Employment Agreement between Owen Kratz and the Company
dated February 28, 1999.
+*10.6 -- Employment Agreement between Martin R. Ferron and the
Company dated February 28, 1999.
+*10.7 -- Employment Agreement between S. James Nelson and the
Company dated February 28, 1999.
+*10.8 -- Employment Agreement between Louis L. Tapscott and the
Company dated February 28, 1999.
+10.9 -- 1998 Annual Incentive Compensation Program.
21.1 -- Subsidiaries of the Registrant. The Company has two
subsidiaries, Energy Resource Technologies, Inc. and Cal Dive
Offshore, Ltd.
*23.1 -- Consent of Arthur Andersen LLP.
*27.1 -- Financial Data Schedule.
- ----------
+ Management contract or compensation plan.
* Filed herewith.
50
SIGNATURES
Pursuant to the requirements option 13 or 15 (d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned.
thereunto duly authorized.
CAL DIVE INTERNATIONAL, INC.
By: /s/ S. JAMES NELSON
S. James Nelson
Executive Vice President, Chief
Financial Officer
March 29, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
/s/OWEN KRATZ Chairman, Chief Executive Officer March 29, 1999
Owen Kratz and Director
/s/MARTIN R. FERRON President, Chief Operating Officer March 29, 1999
Martin R. Ferron and Director
/s/S. JAMES NELSON Executive Vice President, Chief March 29, 1999
S. James Nelson Financial Officer and Director
/s/A. WADE PURSELL
A. Wade Pursell Vice President-Finance, Chief March 29, 1999
Accounting Officer
/s/WILLIAM E. MACAULAY Director March 29, 1999
William E. Macaulay
/s/BEN GUILL Director March 29, 1999
Ben Guill
/s/GORDON F. AHALT Director March 29, 1999
Gordon F. Ahalt
THOMAS M. EHRET Director March 29, 1999
JEAN-BERNARD FAY Director March 29, 1999
KEVIN WOOD Director March 29, 1999
51