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 1 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 2 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. 3 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 4 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 6 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 7 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