-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KqSZZAfRLu+GyFuhprUbD7cZ4EZp6AJz/PfClZEe+hDpH8TY+77O7BsEEkmFEFHD /1hNekoVpVxplpxxOhpHqg== 0000950129-00-001545.txt : 20000331 0000950129-00-001545.hdr.sgml : 20000331 ACCESSION NUMBER: 0000950129-00-001545 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CAL DIVE INTERNATIONAL INC CENTRAL INDEX KEY: 0000866829 STANDARD INDUSTRIAL CLASSIFICATION: OIL, GAS FIELD SERVICES, NBC [1389] IRS NUMBER: 953409686 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-22739 FILM NUMBER: 587947 BUSINESS ADDRESS: STREET 1: 400 N SAM HOUSTON PKWYE STREET 2: SUITE 400 CITY: HOUSTON STATE: TX ZIP: 77060 BUSINESS PHONE: 7136901818 MAIL ADDRESS: STREET 1: 400 N SAM HOUSTON PKWY E STREET 2: SUITE 400 CITY: HOUSTON STATE: TX ZIP: 77060 10-K 1 CAL DIVE INTERNATIONAL, INC. - DATED 12/31/1999 1 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NO. 0-22739 CAL DIVE INTERNATIONAL, INC. (Exact name of registrant as specified in its charter) MINNESOTA 95-3409686 (State or other jurisdiction of (I.R.S. Employer incorporation of organization) Identification No.)
400 N. SAM HOUSTON PARKWAY E., 77060 SUITE 400 (Zip Code) HOUSTON, TEXAS (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 24, 2000 was $341,003,415 based on the last reported sales price of the Common Stock on March 24, 2000, as reported on the NASDAQ/National Market System. The number of shares of the registrant's Common Stock outstanding as of March 24, 2000 was 15,664,658. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 10, 2000 are incorporated by reference into Part III hereof. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 2 CAL DIVE INTERNATIONAL, INC. ("CDI") INDEX -- FORM 10-K
PAGE ---- PART I Item 1. Business.................................................... 1 Item 2. Properties.................................................. 13 Item 3. Legal Proceedings........................................... 16 Item 4. Submission of Matters to a Vote of Security Holders......... 16 Unnumbered Item Executive Officers of Registrant............................ 16 PART II Item 5. Market for the Registrant's Common Equity and Related Shareholder Matters......................................... 18 Item 6. Selected Financial Data..................................... 19 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................... 20 Results of Operations....................................... 22 Liquidity and Capital Resources............................. 23 Item 7A Quantitative and Qualitative Disclosure About Market Risk... 26 Item 8. Financial Statements and Supplementary Data................. 27 Independent Auditors' Report................................ 28 Consolidated Balance Sheets -- December 31, 1999 and 1998... 29 Consolidated Statements of Operations -- Three Years Ended December 31, 1999........................................... 30 Consolidated Statements of Shareholders' Equity -- Three Years Ended December 31, 1999............................... 31 Consolidated Statements of Cash Flows -- Three Years Ended December 31, 1999........................................... 32 Notes to Consolidated Financial Statements.................. 33 Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.................................... 46 PART III Item 10. Directors and Executive Officers of the Registrant.......... 46 Item 11. Executive Compensation...................................... 46 Item 12. Security Ownership of Certain Beneficial Owners and Managers.................................................... 46 Item 13. Certain Relationships and Related Transactions.............. 46 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......................................................... 47 Signatures.................................................. 49
i 3 PART I ITEM 1. BUSINESS. Summary Cal Dive International, Inc., together with its subsidiaries, is a leading subsea development contractor providing services from the shallowest to the deepest waters in the Gulf of Mexico. Over three decades, we have earned a reputation for innovation both in partnering with our customers and in underwater construction techniques and equipment. With a diversified fleet of 15 vessels, along with barges available under an alliance, our work covers the life of an offshore natural gas or oil field. Through one of our subsidiaries, Energy Resource Technology, Inc. ("ERT"), we acquire mature offshore properties to provide a cost effective alternative to the decommissioning process. Our customers include major and independent natural gas and oil producers, pipeline transmission companies and offshore engineering and construction firms. In Gulf water depths greater than 1,000 feet, we are a leader in solving technological challenges encountered in the "Deepwater". Many of our Deepwater projects from 1999 forward will involve use of unique techniques or technologies we have developed (including the patent on the design of our new vessel Q4000). With a fleet of six Deepwater-capable vessels, we have a technically diverse fleet for the delivery of these subsea solutions. We have also formed alliances with other offshore service and equipment providers and customers which enhance our ability to provide full field and life of field services. In shallow water depths up to 1,000 feet, we are a dominant provider of services which include air and SAT diving. Fourteen of our vessels perform these services, five of which support SAT diving. In 1999, we doubled the size and management strength of our shallow dive operations by purchasing the shares of Aquatica we did not already own. We also completed five projects involving shallow water full-field development/pipelay bringing new wells online at low cost and in a short period of time (as little as 17 weeks). We are a leader in the operation and decommissioning of mature oil and gas properties in the shallow water Gulf of Mexico. Our salvage assets set an all-time revenue record in 1999 despite a weak market. Through our subsidiary ERT, we are one of few companies with the combined attributes of financial strength, reservoir engineering, operations expertise and company-owned salvage assets that is acquiring and operating mature properties in the Gulf of Mexico. In 1999, ERT doubled its properties and increased production levels 82% over 1998. Overview of 1999 Developments 1999 began with our customer base frozen by low commodity prices and mega-merger activity. As commodity prices improved, however, indicators of construction activity (including the mobile rig count) remained flat as did offshore completion and construction work. Rather than going head-to-head with competitors in the Gulf market, our strategy shifted to focus on four unique actions: (i) negotiating large contracts where we functioned as general contractor (see "General Contractor Projects" below); (ii) completing projects in our new business unit using a modular package for fast-track full-field development (see "Shallow Full-Field Development" below); (iii) doubling the size of ERT by purchasing new offshore blocks (see "ERT Growth" below); and (iv) purchasing the Cal Dive Aker Dove under favorable terms (see "Deepwater Vessels" below). As a result, we were able to achieve substantially all of our below stated 1999 goals: - a return on invested capital of over 12%; - double ERT revenues; - combined Salvage revenues (including ERT and barge operations) equal to 30% of total revenues; - expand our role as a general contractor; - utilize the DP fleet to solve Deepwater problems; and - commence construction of the Q4000. 1 4 Overall, we earned business with our specialized fleet, ability to manage complex projects and our unique structure. We also closed 1999 with over $20 million cash on hand and no debt. Our clean balance sheet and strong performance suggests that we have weathered the storm of volatile commodity prices better than most. While difficult to forecast, we believe we are well positioned for the recovery that downturns such as 1998/1999 have produced in the past. General Contractor Projects Examples of large negotiated general contractor projects in 1999 include: - In March of 1999, we were awarded a shallow water salvage contract (the largest such contract in our history) to decommission Sabine Pass No. 9 involving removal of nine (9) structures with 24 wells and 30 pipelines. This complex work involved not only our barge and vessel assets but also project management of equipment from a number of alliance partners. - During the summer of 1999, the MSV Uncle John established a deepwater record for a subsea construction vessel at Exxon's high profile Diana field. We installed two 50-ton suction piles, a 70 and 92-ton manifold and five subsea trees in 4,800 feet of water. We believe this is the first time a vessel other than a drilling rig has ever completed such tasks. All of the items were lowered to the seabed on a drillstring from the derrick on the Uncle John, while two Triton XL ROV systems handled positioning. The project saved Exxon an estimated 20% from the drill rig rates of the third quarter. A unique aspect of the project involved a material barge positioning the 92-ton manifold beneath the Uncle John, with the vessel then lifting the manifold on its derrick before lowering to the ocean floor. This unique approach will be an integral feature of the Q4000. - During the third and fourth quarter of 1999, we undertook the Cooper field abandonment, the first ever Deepwater subsea decommissioning project in the Gulf of Mexico. We removed a large freestanding production riser, a 12-point mooring system, the floating production unit and a variety of subsea equipment. Three of our vessels, the Uncle John, Witch Queen and Dove, performed a number of complex operations including solving unanticipated downhole conditions such as paraffin blockages and hydrates. Technical aspects of the project, the largest ever undertaken by Cal Dive, were featured in Offshore magazine. Full-Field Development In 1999, we launched our new full field development product line to assist cash constrained customers on the Outer Continental Shelf. With 4,000 platforms and production facilities already in place in the Gulf, our underlying premise is that each new field need not be re-engineered. Adapting industry standard designs we now stock subsea trees, prefabricated modules, well panels and controls and umbilicals for immediate assembly. In 1999, we completed five full field/pipelay projects including installations for Soco, now Santa Fe Snyder, Tana Oil and Gas, and ATP. The development for SOCO was a comprehensive contracting effort which included the stocked subsea mudline tree and controls from FMC. The time elapsed between contract signature and commissioning of the well, flowlines and controls system was one hundred and two days. The Tana Oil and Gas project was an installation of a 60inches x 48inches caisson/well protector. The caisson was braced after being driven to grade by 42inches pile and topped off with the 35feet x 40feet deck and heliport from our pre-engineered deck package. On the ATP Oil and Gas project, we subcontracted to our alliance partner, Horizon Offshore, for the winter installation of our second deck facility package. ERT Growth In 1999, the collapse of commodity prices allowed us to quickly increase ERT's mature property base by acquiring 20 offshore blocks and tripling the number of operated wells. We then implemented a well exploitation program which included the acquisition of 3D seismic and five rig recompletions. As a result, 2 5 monthly production increased to almost one BCF equivalent during the fourth quarter, an increase of 82% over the first half of 1999 and a level three times that of the same period in 1998. The following ERT operating policies were also utilized during 1999 -- we will sell ERT assets (offshore leases, platforms, compressors, etc.) when the expected future revenue stream can be accelerated in a single transaction, and; ERT is not in the exploration business. When 3D seismic identified a prospect which was successfully drilled by Hall-Houston, they proposed drilling a second well. ERT instead negotiated a sale of its interest in the two blocks involved. New Deepwater Vessels Two developments relating to assets which are part of our Deepwater strategy occurred in 1999. First, we waited for weak industry conditions to create an opportunity to acquire a Deepwater vessel in a distressed financial situation. We moved quickly to acquire an interest in the Cal Dive Aker Dove, a transaction which took a total of three weeks to identify and close. The Dove gives us earlier access to capabilities planned with the converted Sea Sorceress and at a lower price, while moving us further upstream into the high technology applications of pre-set moorings and suction pile anchoring. We also commenced construction of our Q4000, our sixth generation, semi-submersible multi-service vessel which we believe will greatly improve the economics of Deepwater completion and construction operations. The $150 million vessel is expected to be christened in mid-2001, in time for the next round of Deepwater construction activities. DESCRIPTION OF OPERATIONS The Industry and CDI The subsea services industry in the Gulf of Mexico originated in the early 1960s to assist natural gas and oil companies with offshore operations. The industry has grown significantly since the early 1970s as the domestic oil and gas industry has increasingly relied upon offshore fields for new production. Subsea services are required throughout the economic life of an offshore field and include the following services, among others: - Exploration. Pre-installation survey; rig positioning and installation assistance; drilling inspection; subsea equipment maintenance; well completion; search and recovery operations. - Development. Installation of production platforms; installation of subsea production systems; pipelay support including connecting pipelines to risers and subsea assemblies; pipeline stabilization, testing and inspection; cable and umbilical lay and connection. - Production. Inspection, maintenance and repair of production structures, risers and pipelines and subsea equipment; well intervention; life of field support. - Decommissioning. Decommissioning and remediation services; plugging and abandonment services; platform salvage and removal; pipeline abandonment; site inspections. Defined below are certain terms and business concepts helpful to understanding the services CDI performs in support of offshore development: Dive Support Vessel (DSV): Specially equipped vessel which performs services and acts as an operational base for divers, ROVs and specialized equipment. Dynamic positioning (DP): Computer-directed thruster systems that use satellite-based positioning combined with other positioning technologies to ensure the proper counteraction to wind, current and wave forces enabling the vessel to maintain its position without the use of anchors. Two DP systems are required to provide the redundancy necessary to support safe deployment of divers where only a single DP system is necessary to support ROV operations. Moonpool: An opening in the center of a vessel through which a SAT diving system or ROV may be deployed, allowing the safest diver or ROV deployment in adverse weather conditions. 3 6 Remotely Operated Vehicle (ROV): Robotic vehicles used to complement, support and increase the efficiency of diving and subsea operations and for tasks beyond the capability of manned diving operations. Saturation (SAT) Diving: SAT diving, required for work in water depths greater than 300 feet, involves divers working from special chambers for extended periods at a pressure equivalent to the depth of the work site. Spot Market: Market prevalent in to the Gulf of Mexico characterized by projects generally short in duration and often of a turnkey nature. These projects often require constant rescheduling and the availability or interchangeability of multiple vessels. Subsea Construction Vessels. Subsea services are typically performed with the use of specialized construction vessels which provide an above water platform that functions as an operational base for divers in water depths up to 1,000 feet and ROVs at all water depths. Distinguishing characteristics of subsea construction vessels include DP systems, SAT diving capabilities, deck space, deck load, craneage and moonpool launching. Deck space, deck load and craneage are important features of the vessel's ability to transport and fabricate hardware, supplies and equipment necessary to complete subsea projects. Production Contracting. Producers may desire to have a development contractor involved as a working interest partner in a project to assure that the contractor/producer interests are truly collaborative. A production participation deal can be the enabler for securing contracting work. Full-Field Development. Subsea contractors offer oil and gas companies a range of services from subcontracting to complete field development solutions. We are able to provide a broad range of subsea systems and services, from procurement and installation of flowlines, wellheads, control systems, umbilicals and manifolds to installation and commissioning of the complete production system. Many oil and gas companies prefer to contract with a consortium capable of undertaking major portions or all of an entire field development project. Full field development services can relieve a customer of a substantial amount of the burdens of management of field development. Deepwater Technologies In 1994, we began to assemble a fleet of DP vessels which are required to deliver subsea services in the Deepwater. Our Deepwater fleet now consists of one semisubmersible DP MSV (the Uncle John), four DP DSV's (the Witch Queen, the Balmoral Sea, the Merlin and the Cal Dive Aker Dove), one Deepwater service barge (the Sea Sorceress), two 4-point moored saturation DSVs (the Cal Diver, I and the Cal Diver II) and one work class ROV. In 1999, we also commenced construction of our six-generation DP MSV the Q4000. Most vessels currently working the Deepwater Gulf (competitors and ours) were designed in the 1970's for work to a maximum depth of approximately 1,000 fsw. Many of these assets have been modified to apply new technologies out to 4,000 fsw. We designed the Q4000 as a best in class solution to 4000 feet with unique further capabilities specifically designed to work at 10,000 feet. Its multi-purpose design allows it to be considered as an alternative to the drilling rig at that point when it transitions to become a completion support vessel (i.e. the 30 to 45 days it typically takes to work on setting the tree, connecting flow lines and testing the well). The vessel is ideally suited to the long term life of field work that is required including well intervention. We have applied for patents covering over 50 specific aspects of the vessel, including the 52-meter three-faced derrick, the underslung cartridge for pipelay, and a hull structure that does not require cross-bracing. In 1999, our traditional customer base was not very active. Our 1999 strategy resulted in the expansion of small subcontract positions into two major projects, at the Diana and Cooper fields, both of which were 4 7 highlighted in the technology section of Offshore magazine and are described in "Overview of 1999 Developments". Other significant Deepwater projects included:
DEPTH FIELD CUSTOMER DESCRIPTION (FSW) - ----- ------------ ----------- ----- Diana................... Exxon Mobil Deepest installation work by 4,700 non-drilling rig Mars.................... Shell Installation of expansion joints 3,000 Cooper.................. EEX First ever decommissioning of GOM 2,200 Deepwater field Typhoon................. Chevron Geotechnical coring 2,100 Troika.................. BP/Amoco Establish flange connection on rigid 1,800 jumpers Baldpate................ Amerada Hess Tie-in production from Penn State field 1,650 Pompano................. Exxon Mobil Pig J tube and pull test umbilical 1,300 Gyrfalcon............... Shell Tie-in production from the deployment 1,000 of 15,000 psi subsea tree
Our Business Development Group, formed in 1996 to cover the emerging Deepwater market, was recently expanded to include life of field services such as well intervention and production contracting. This Group coordinates our efforts with alliance partners as described below:
ALLIANCE DESCRIPTION - -------- ----------- Schlumberger, Ltd........................ Alliance Agreement whereby we provide DP vessels and related operating services for well servicing and testing Fugro-McClelland Marine Geoscience, Performance Contract whereby we provide Inc. .................................. vessels for geoscience services and coring work TOPS..................................... Preferred Provider Agreement whereby we provide subsea marine contracting services in a full field development setting to TOPS in the Deepwater Gulf of Mexico Canyon................................... Alliance Agreement where Canyon supports our ROV operations and provides ROV personnel/equipment
We are also involved in a number of efforts to solve technical challenges of projects in the Deepwater. For example, a number of wells were lost in 1998 and 1999 to shallow sand flow, a geological phenomenon unique to the Deepwater Gulf. We are working with an oil company in the development of a newly designed hammer to drive a caisson 2,000 feet into the ocean floor in order to solve flow problems. We are also cooperating with a technology group to develop deepwater tooling and connectors. In each case our goal is to promote development of new Deepwater products which can be deployed from our fleet of DP vessels. Traditional Subsea Services Subsea services performed in shallow waters involve air and saturation (SAT) diving in support of marine construction activities. We believe that we are the largest provider of SAT diving services and operate the largest fleet of SAT diving vessels permanently deployed in the Gulf. All of our SAT diving vessels have moonpool systems. The services provided by our vessels both overlap and are complementary in a number of market segments, enabling us to deploy our vessels to areas of highest utility and margin potential. In 1999, we launched our new full-field development product line to assist cash-constrained customers on the OCS described in "Overview of 1999 Developments". It was a tough year, however, in this part of our business. The revenues of our vessels that work the OCS were down 26% while those of Aquatica were off 22%. Our dominant presence, however, allowed us to maintain profit margins at a respectable 37%. 5 8 The industry lost a significant number of experienced subsea people in 1999 due to the downturn. We do not believe people will be a constraint upon our growth. Our offshore hands and those working at our Operations Base in Morgan City realized 90% of what they earned in 1998, a record year for our direct labor. Among other things,this is due to over $2 million of salvage and repair work our Subsea Services group performed for ERT, most of that coming in the particularly slow first half of 1999. In August of 1999 we acquired the 55% of Aquatica, Inc. we did not already own. Aquatica was created in 1997 to take advantage of a void that opened in the shallow water market (from the beach to 300 fsw). Sonny Freeman, formerly the Chief Operating Officer of American Oilfield Divers, has attracted a management team which has developed a reputation for customer service far beyond that normally rendered in this market segment. We have now concentrated all shallow water assets under Aquatica management. Aquatica's fleet currently includes four DSV's (the Cal Diver III and Mr. Jim, Mr. Joe and Mr. Jack) with delivery of a fifth DSV (the Cal Diver IV) expected during 2000. Salvage Services Since 1997, we have established a leading position in the decommissioning of facilities in the shallow water of the Gulf of Mexico. According to Offshore magazine, we performed 24% of all structure removal projects in the Gulf from January 1, 1996 through June 30, 1998. In 1999, our salvage assets set a new all time revenue record even though the market was flat compared to the prior year. The largest Deepwater and OCS decommissioning projects in our history were also completed in 1999. In addition to the Cooper and Sonat field projects described in "Overview of 1999 Developments", we were also awarded a Chevron package of small structure removals (20 caissons and two platforms) and undertook salvage projects for Samedan, Murphy Oil, Chocktaw Oil and Gas, and Forcenergy. The subcontracting of Horizon Offshore derrick and pipelay barges to support the decommissioning of large structures and shallow full-field projects added $10 million to 1999 revenues from this alliance and new product line. We formed ERT in 1992 to exploit a market opportunity to provide a more efficient solution to offshore abandonment, to expand our off-season salvage and decommissioning activity and to support full-field production development projects. We have assembled and expanded its team of personnel experienced in geology, geophysics, reservoir, drilling, production engineering, facilities management and lease operations to allow ERT to better meet each of these goals. ERT makes its money in three ways: lower salvage costs using our assets, operating the field more cost effectively, and extending reservoir life through well exploitation operations. The collapse of commodity prices early in 1999 took many of the small companies which buy mature properties out of the market. The financial difficulties that these companies experienced also reminded the majors and large independents that they must again assume responsibility when buyers having little salvage experience are not able to perform the abandonment obligation. As a result, ERT was able to double the number of operated properties (and triple the number of wells operated) early in 1999. We then conducted a successful well exploitation program which increased 1999 production by 4 BCFe, or 82% over 1998 levels. In addition, three of the properties acquired are oilfields which took oil and condensate production to 40% of ERT fourth quarter revenues, up from our historical average of 10%. For certain financial information related to each of our business segments, including revenues, income from operations and total assets, see Notes to Consolidated Financial Statements, Note 11, included elsewhere in this Form 10-K." CUSTOMERS Our customers include major and independent natural gas and oil producers, pipeline transmission companies and offshore engineering and construction firms. The level of construction services required by any particular customer depends on the size of that customer's capital expenditure budget devoted to construction plans in a particular year. Consequently, customers that account for a significant portion of contract revenues in one fiscal year may represent an immaterial portion of contract revenues in subsequent fiscal years. We estimate that in 1999 we provided subsea services to approximately 100 customers. EEX Corporation, accounted for 13% of consolidated revenues in 1999. In addition, Chevron USA accounted for 11% of 6 9 consolidated revenues in 1998. Our projects are typically of short duration and are generally awarded shortly before mobilization. Accordingly, backlog is not a meaningful indicator of future activities. COMPETITION The subsea services industry is highly competitive. Competition has historically been based on factors such as the location and type of equipment available, the ability to deploy such equipment, the safety and quality of service and in recent years price. While price is a factor, the ability to acquire specialized vessels, to attract and retain skilled personnel, and to demonstrate a good safety record are important competitive factors. Our competitors in the shallower waters of the Gulf include Stolt Offshore, Torch, Inc., Global Industries Ltd. and Oceaneering International, Inc. as well as a number of smaller companies, some of which only operate a single vessel, that often compete solely on price. For Deepwater projects, our principal U.S. based competitors include Oceaneering International, Inc., Global Industries, Ltd. and Stolt Offshore. Other large foreign based subsea contractors, including, Coflexip, DSND Ltd, Saipem and Rockwater, Ltd., may perform services in the Gulf. We also encounter significant competition for the acquisition of producing natural gas and oil properties. Our ability to acquire additional properties also depends upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our competitors are well-established companies with substantially larger operating staffs and greater capital resources. TRAINING, SAFETY AND QUALITY ASSURANCE We have established a corporate culture in which safety is understood to be and is accepted as the number one priority. Our corporate goal, based on the belief that all accidents are preventable, is to provide an injury-free workplace by focusing on correct safety behavior. Our safety procedures and training programs were developed by management personnel who came into the industry as divers and who know first hand the physical challenge of the ocean work site. As a result, management believes that our safety programs are among the best in the industry. GOVERNMENT REGULATION Many aspects of the offshore marine construction industry are subject to extensive governmental regulation. The Company is subject to the jurisdiction of the United States Coast Guard ("Coast Guard"), the Environmental Protection Agency, Minerals Management Service ("MMS") and the U.S. Customs Service ("USCS") as well as private industry organizations such as the American Bureau of Shipping ("ABS"). We support and voluntarily comply with the Association of American Diving Contractor Standards. The Coast Guard sets safety standards and is authorized to investigate vessel and diving accidents and recommend improved safety standards, and the Coast Guard is authorized to inspect vessels at will. We are required by various governmental and quasi-governmental agencies to obtain certain permits, licenses and certificates with respect to its operations. We believe that we have obtained or can obtain all permits, licenses and certificates necessary for the conduct of its business. In addition, we depend on the demand for our services from the oil and gas industry and, therefore, our business is affected by laws and regulations, as well as changing taxes and policies relating to the oil and gas industry generally. In particular, the development and operation of natural gas and oil properties located on the Outer Continental Shelf ("OCS") of the United States is regulated primarily by the MMS. The MMS requires lessees of OCS properties to post bonds in connection with the plugging and abandonment of wells located offshore and the removal of all production facilities. Operators in the Outer Continental Shelf waters are currently required to post an area wide bond of $3.0 million or $500,000 per producing lease. We currently have bonded our offshore leases as required by the MMS. Under certain circumstances, the MMS has the authority to suspend or terminate operations on federal leases. Any such 7 10 suspensions or terminations of our operations could have a material adverse effect on our financial condition and results of operations. We acquire production rights to offshore mature oil and gas properties under federal oil and gas leases, which the MMS administers. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA") (which are subject to change by the MMS). The MMS has promulgated regulations requiring offshore production facilities located on the Outer Continental Shelf to meet stringent engineering and construction specifications. These latter regulations were withdrawn pending further discussions among interested federal agencies. The MMS also has issued regulations restricting the flaring or venting of natural gas and prohibiting the burning of liquid hydrocarbons without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. Finally, under certain circumstances, the MMS may require any operations on federal leases to be suspended or terminated, and the MMS has recently proposed, but not yet enacted, regulations that would allow it to expel unsafe operators from existing Outer Continental Shelf platforms and bar them from obtaining future leases. The MMS has issued a final rule governing the calculation of royalties and the valuation of crude oil produced from federal leases. The rule modifies the valuation procedures for both arm's length and non-arm's length crude oil transactions to decrease reliance on oil posted prices and assign a value to crude oil that better reflects market value, establishes a new MMS form for collecting value differential data, and amend the valuation procedure for the sale of federal royalty oil. This rule might affect our operation. In addition, the MMS recently issued a final rule amending its regulations regarding costs for gas transportation which are deductible for royalty valuation purposes when gas is sold offlease. Among other matters, for purposes of computing royalty owed, the rule disallows as deductions certain costs, such as aggregator/marketer fees and transportation imbalance charges and associated penalties. The rule, however, was enjoined on March 28, 2000. Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the past, the federal government has regulated the prices at which gas and oil could be sold. While sales by producers of natural gas, and all sales of crude oil, condensate, and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended the NGPA to remove both price and non-price controls from natural gas sold in "first sales" no later than January 1, 1993. Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and FERC final decisions. We cannot predict what further action the FERC will take on these matters, however, we do not believe that we will be affected by any action taken materially differently than other companies with which we compete. 8 11 Additional proposals and proceedings before various federal and state regulatory agencies and the courts could affect the oil and gas industry. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by the FERC will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules, and regulations will have a material effect upon the capital expenditures, earnings, or competitive position. ENVIRONMENTAL REGULATIONS Our operations are subject to a variety of federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often complex and costly to comply with, and that carry substantial administrative, civil and possibly criminal penalties for failure to comply. Aside from possible liability for damages and costs associated with releases of hazardous materials including oil into the environment, such laws and regulations may impose liability on us for the conduct of or conditions caused by others, or by our acts that were in compliance with all applicable laws at the time such acts were performed. The Oil Pollution Act of 1990, as amended ("OPA"), imposes a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. A "responsible party" includes the owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. OPA imposes liability on each responsible party for oil spill removal costs and for other public and private damages from oil spills. Failure to comply with OPA may result in the assessment of civil and criminal penalties. OPA establishes liability limits of up to $350 million for onshore facilities, all removal costs plus up to $75 million for offshore facilities, and the greater of $500,000 or $600 per gross ton for vessels other than tank vessels. The liability limits are not applicable, however, if the spill is caused by gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction, or operating regulation, or if a party fails to report a spill or fails to cooperate fully in the cleanup. Few defenses exist to the liability imposed under OPA. Management is currently unaware of any oil spills for which we have been designated as a responsible party under OPA that will have a material adverse impact on us or our operations. OPA also imposes ongoing requirements on a responsible party including preparation of an oil spill contingency plan and proof of financial responsibility to cover a majority of the costs in a potential spill. We believe we have appropriate spill contingency plans in place. Vessels subject to OPA other than tank vessels are subject to financial responsibility limits of the greater of $500,000 or $600 per gross ton, while offshore facilities are subject to financial responsibility limits of not less than $35 million, with that limit potentially increasing up to $150 million if a formal risk assessment indicates that a greater amount is required. The MMS has promulgated regulations implementing these financial responsibility requirements for covered offshore facilities. Under the MMS regulations, the amount of financial responsibility required for an offshore facility is increased above the minimum amounts of the "worst case" oil spill volume calculated for the facility. We believe that we currently have established adequate proof of financial responsibility for our vessels and onshore and offshore facilities and that we satisfy the MMS requirements for financial responsibility under OPA and the proposed regulations. OPA also requires owners and operators of vessels over 300 gross tons to provide the Coast Guard with evidence of financial responsibility to cover the cost of cleaning up oil spills from such vessels. We currently own and operate six vessels over 300 gross tons. Satisfactory evidence of financial responsibility has been provided to the Coast Guard for all of our vessels. The Clean Water Act imposes strict controls on the discharge of pollutants into the navigable waters of the U.S., and imposes potential liability for the costs of remediating releases of petroleum and other substances. The Clean Water Act provides for civil, criminal and administrative penalties for any unauthorized discharge of oil and other hazardous substances and imposes substantial potential liability for the costs of removal, remediation and damages. Many states have laws which are analogous to the Clean Water Act and 9 12 also require remediation of releases of petroleum and other hazardous substances in state waters. Our vessels routinely transport diesel fuel to offshore rigs and platforms, and also carry diesel fuel for their own use. Our supply boats transport bulk chemical materials used in drilling activities, and also transport liquid mud which contains oil and oil by-products. Offshore facilities and vessels operated by us have facility and vessel response plans to deal with potential spills of oil or its derivatives. OCSLA provides the federal government with broad discretion in regulating the release of offshore resources of natural gas and oil production as well as regulating safety and environmental protection applicable to lessees and permittees operating in the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and cancellation of leases. Because our operations rely on offshore oil and gas exploration and production, if the government were to exercise its authority under OCSLA to restrict the availability of offshore oil and gas leases, such action could have a material adverse effect on our financial condition and the results of operations. As of this date, we believe we are not the subject of any civil or criminal enforcement actions under OCSLA. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") contains provisions dealing with remediation of releases of hazardous substances into the environment and imposes liability without regard to fault or the legality of the original conduct, on certain classes of persons including owners and operators of contaminated sites where the release occurred and those companies who transport, dispose of or who arrange for disposal of hazardous substances released at the sites. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. Third parties may also file claims for personal injury and property damage allegedly caused by the release of hazardous substances. Although we handle hazardous substances in the ordinary course of business, we are not aware of any hazardous substance contamination for which we may be liable. Management believes we are in compliance in all material respects with all applicable environmental laws and regulations to which we are subject. We do not anticipate that compliance with existing environmental laws and regulations will have a material effect upon the capital expenditures, earnings or competitive position. However, changes in the environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities and thus there can be no assurance that we will not incur significant environmental compliance costs in the future. EMPLOYEES We rely on the high quality of our workforce and have successfully hired, trained, and retained skilled managers and divers. As of December 31, 1999, we had 883 employees, 138 of which were salaried. As of that date we also utilized approximately 105 non-US citizens to crew our foreign flag vessels under a crewing contract with C-MAR Services (UK), Ltd. of Aberdeen, Scotland. None of our employees belong to a union or are employed pursuant to any collective bargaining agreement or any similar arrangement. Management believes that our relationship with our employees and foreign crew members is good. Of our employees, approximately 94 persons own shares of Common Stock and 72 other employees hold options to acquire Common Stock under the Company's 1995 Long Term Incentive Plan, as amended. FACTORS INFLUENCING FUTURE RESULTS AND ACCURACY OF FORWARD LOOKING INFORMATION Shareholders should carefully consider the following risk factors in addition to the other information contained in this Annual Report. This Annual Report on Form 10-K includes certain statements that may be deemed "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. All statements, other than statements of historical facts, included in this Annual Report that relate to business plans or strategies, projected or anticipated benefits or other 10 13 consequences of such plans or strategies, projected or anticipated benefits from acquisitions made by or to be made by us or projections involving anticipated revenues, earnings, or other aspects of operating results are forward-looking statements. The words "expect," "believe," "anticipate," "project," "estimate," and similar expressions are intended to identify forward-looking statements. We caution readers that such statements are not guarantees of future performance or events and are subject to a number of factors that may tend to influence the accuracy of the statements and the projections upon which the statements are based, including but not limited to those discussed below. As noted elsewhere, all phases of our operations are subject to a number of uncertainties, risks and other influences, many of which are outside our control, and any one or a combination of which could materially affect the results of our operations and the accuracy of forward-looking statements made by us. The following discussion outlines certain factors that could affect our consolidated results of operations for 2000 and beyond and cause them to differ materially from those that may be set forth in forward-looking statements made by or on our behalf. OUR BUSINESS IS ADVERSELY AFFECTED BY LOW OIL AND GAS PRICES AND BY THE CYCLICALITY OF THE OIL AND GAS INDUSTRY. Our business is substantially dependent upon the condition of the oil and gas industry and, in particular, the willingness of oil and gas companies to make capital expenditures on exploration, drilling and production operations offshore. The level of capital expenditures generally depends on the prevailing view of future oil and gas prices, which are influenced by numerous factors affecting the supply and demand for oil and gas, including worldwide economic activity, interest rates and the cost of capital, environmental regulation, tax policies, coordination by the Organization of Petroleum Exporting Countries ("OPEC"), the cost of exploring for and producing oil and gas, the sale and expiration dates of offshore leases in the United States and overseas, the discovery rate of new oil and gas reserves in offshore areas and technological advances. The level of offshore drilling and production activity did not increase the second half of 1999 despite higher commodity prices. There can be no assurance that activity levels will increase any time soon. A sustained period of low drilling and production activity or a return of low hydrocarbon prices would likely have a material adverse effect on our financial position and results of operations. THE OPERATION OF MARINE VESSELS IS RISKY AND WE DO NOT HAVE INSURANCE COVERAGE FOR ALL RISKS. Marine construction involves a high degree of operational risk. Hazards, such as vessels sinking, grounding, colliding and sustaining damage from severe weather conditions, are inherent in marine operations. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Damage arising from such an occurrence may result in lawsuits asserting large claims. We maintain such insurance protection as we deem prudent, including Jones Act employee coverage (the maritime equivalent of workers compensation) and hull insurance on our vessels and have never had a claim involving major damage or pollution involving our vessels. There can be no assurance that any such insurance will be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on us. Moreover, no assurance can be given that we will be able to maintain adequate insurance in the future at rates that we consider reasonable. As construction activity moves into deeper water in the Gulf of Mexico, construction projects tend to be larger and more complex than shallow water projects. As a result, our revenues and profits are increasingly dependent on our larger vessels. While we currently insure our vessels against property loss due to a catastrophic marine disaster, mechanical failure or collision, the loss of any of our large vessels as a result of such event could result in a substantial loss of revenues, increased costs and other liabilities and could have a material adverse effect on our operating performance. To date, we have not been involved in any such significant claims or litigation. OUR BUSINESS DECLINES IN WINTER AND BAD WEATHER IN THE GULF OF MEXICO CAN ADVERSELY AFFECT OUR OPERATIONS. Marine operations conducted in the Gulf of Mexico are seasonal and depend, in part, on weather conditions. Historically, we have enjoyed our highest vessel utilization rates during the summer and fall when 11 14 weather conditions are favorable for offshore exploration, development and construction activities and have experienced our lowest utilization rates in the first quarter. During certain periods of the year, we typically bear the risk of delays caused by adverse weather conditions. Accordingly, the results of any one quarter are not necessarily indicative of annual results or continuing trends. IF WE BID TOO LOW ON A CONTRACT WE SUFFER THE CONSEQUENCES. A majority of our projects are currently performed on a qualified turnkey basis where described work is delivered for a fixed price and extra work is charged separately. The revenue, cost and gross profit realized on a contract can vary from the estimated amount because of changes in offshore job conditions, variations in labor and equipment productivity from the original estimates and performance of others such as alliance partners. These variations and risks inherent in the marine construction industry may result in our experiencing reduced profitability or losses on projects. THE ESTIMATES OF OUR NATURAL GAS AND OIL RESERVES AND FUTURE CASH FLOWS MAY BE SIGNIFICANTLY INCORRECT. This report contains an estimate of our proved natural gas and oil reserves and the estimated future net cash flows therefrom based upon a report prepared as of December 31, 1999 by Miller & Lents. That report relies upon various assumptions, including assumptions required by the Securities and Exchange Commission as to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas and oil reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, these estimates are inherently imprecise. Actual future production, cash flows, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from those estimated in the report. Any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. OUR NATURAL GAS AND OIL OPERATIONS INVOLVE SIGNIFICANT RISKS AND WE DO NOT HAVE INSURANCE COVERAGE FOR ALL RISKS. Our natural gas and oil operations are subject to the usual risks incident to the operation of natural gas and oil wells, including, but not limited to, uncontrollable flows of oil, natural gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions, pollution and other risks, any of which could result in substantial losses to us. Although we have had no significant claims of this nature to date, in accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. WE MAY NOT BE ABLE TO COMPETE SUCCESSFULLY AGAINST CURRENT AND FUTURE COMPETITORS. The business in which we operate is highly competitive. Several of our competitors are companies that are substantially larger and have greater financial and other resources than we have. If other companies relocate or acquire vessels for operations in the Gulf of Mexico, levels of competition may increase and our business could be adversely affected. THE LOSS OF THE SERVICES OF ONE OR MORE OF OUR KEY PERSONNEL, OR OUR FAILURE TO ATTRACT, ASSIMILATE AND RETAIN OTHER HIGHLY QUALIFIED PERSONNEL IN THE FUTURE, COULD DISRUPT OUR OPERATIONS AND RESULT IN LOSS OF NET SALES. Our success depends on the continued active participation of key management personnel. The loss of key people could adversely affect our operations. We have multi-year employment and non-compete agreements with all of our senior officers. We believe that our success and continued growth is also dependent upon our ability to employ and retain skilled personnel. While we believe that our wage rates are competitive and that our relationship with our workforce is good, a significant increase in the wages paid by other employers could result in a reduction in the Company's workforce, increases in the wage rates we pay, or both. If either of these 12 15 events occur for any significant period of time, our profitability could be diminished and our growth potential could be impaired. WE MAY NEED TO CHANGE THE MANNER IN WHICH WE CONDUCT ONE BUSINESS IF GOVERNMENT REGULATION INCREASES. Our subsea construction, inspection, maintenance and decommissioning operations and our natural gas and oil production from offshore properties (including decommissioning of such properties) are subject to and affected by various types of government regulation, including numerous federal, state and local environmental protection laws and regulations. These laws and regulations are becoming increasingly complex, stringent and expensive and there can be no assurance that continued compliance with existing or future laws or regulations will not adversely affect our operations. Significant fines and penalties may be imposed for non-compliance. CERTAIN PROVISIONS OF OUR CORPORATE DOCUMENTS AND MINNESOTA LAW MAY DISCOURAGE A THIRD PARTY FROM MAKING A TAKEOVER PROPOSAL. Our Board of Directors has the authority, without any action by the stockholders, to fix the rights and preferences on up to 5,000,000 shares of undesignated preferred stock, including dividend, liquidation and voting rights. In addition, our Articles of Incorporation divide the board of directors into three classes. Except for a transaction involving Coflexip (which is specifically excluded), we are also subject to certain anti-takeover provisions of the Minnesota Business Corporations Act. In addition, we are a party to a Shareholders Agreement that provides Coflexip with a right of first refusal in connection with certain acquisition proposals and we have employment contracts with all of our senior officers which require accelerated vesting of stock options and cash payments in the event of a "change of control". Any or all of the provisions or factors described above may have the effect of discouraging a takeover proposal or tender offer not approved by management and the board of directors and could result in stockholders who may wish to participate in such a proposal or tender offer receiving less for their shares than otherwise might be available in the event of a takeover attempt. ITEM 2. PROPERTIES. MARINE VESSELS AND EQUIPMENT General We own a fleet of 15 vessels and one ROV. The size of our fleet and its capabilities have increased in 1999 with the addition of three (3) smaller Aquatica vessels and the DP DSV Cal Dive Aker Dove. Management believes that the Gulf of Mexico market requires specially designed or equipped vessels to deliver the necessary subsea construction services, especially in the Deepwater. Six of our vessels have DP capabilities specifically designed to respond to the Deepwater market. Five of our vessels also have the permanent capability to provide SAT diving services. New Vessels To gain a greater share of the Deepwater market, in mid-1999 we commenced construction of the world's first sixth-generation multi-service vessel, the MSV Q4000. The vessel is designed to be a new generation of the MSV Uncle John and is unique due to the absence of lower hull cross bracing. Variable deck load of approximately 4,000 metric tons makes the vessel particularly well suited for large offshore construction projects in the Deepwater. High transit speed will allow it to move rapidly from one location to another. We are currently in the process of applying to the US government for construction and permanent MARAD financing on attractive terms. Although no commitment has been obtained from MARAD, management plans to close a financing during the second quarter of 2000 and will fund construction costs in the interim with operating cash and our bank line of credit. 13 16 In June of 1999, we purchased a controlling interest in the DP anchor handling vessel Cal Dive Aker Dove. The vessel is 279 feet long, 65 feet wide, has accommodations for 52 people, a large deck area of 7700 square feet and 1500 tons of deck load capacity. Lifting capability is from a 300 ton A-Frame. In addition to supporting our other vessels, she will provide new up-stream services not previously performed by us, including anchor handling, wire inserts, preset mooring installation, towing, FPSO installation, template/manifold/foundation lowering and supply boat mooring. We contracted to have a replacement vessel built for our utility boat Cal Diver IV as part of our ongoing program to upgrade the quality of our fleet. The original Cal Diver IV was sold to Aquatica in January 1999 (and renamed the Mr. Joe). The new vessel will be 120 feet long, 32 feet wide, have 1,440 feet of clear deck space, a 60 ton deck load capacity and galley accommodations for 24 people. It will be capable of 10 knots cruising speed and is expected to be delivered in 2000. In 1998 we acquired the Sea Sorceress as a DP conversion candidate given her hull (3-inch thick steel) and massive deck capable of carrying a 10,000 metric ton load. In 1999 the vessel was moved to the same Amfels drydock where the Q4000 is being built. The move was due to her Canadian work contract being cancelled. The conversion of the Sea Sorceress (or the acquisition of a similarly configured vessel) is planned in 2000. CAL DIVE INTERNATIONAL, INC. LISTING OF VESSELS, BARGES AND ROVS AS OF DECEMBER 31, 1999
DATE CLEAR DECK MOONPOOL PLACED IN LENGTH SPACE DECK LOAD ACCOM- LAUNCH/ SERVICE (FEET) (SQ. FEET) (TONS) MODATIONS SAT DIVING CRANE CLASSIFICATION(2) --------- ------ ---------- --------- --------- ---------- ----------- ----------------- DP MSV: Uncle John.............. 11/96 254 11,834 460 102 X 2 x 100-ton DNV DP DSVS: Balmoral Sea............ 9/94 259 3,443 250 60 X 30-ton DNV Witch Queen............. 11/95 278 5,600 500 60 X 50-ton DNV Merlin.................. 12/97 198 955 308 42 -- A-Frame ABS Cal Dive Aker Dove...... 9/99 279 7,700 1,500 52 -- 300 ton ABS A-Frame CDI DSVS: Cal Diver I............. 7/84 196 2,400 220 40 X 20-ton ABS Cal Diver II............ 6/85 166 2,816 300 32 X A-Frame ABS Cal Diver V............. 9/91 168 2,324 490 30 -- A-Frame ABS AQUATICA DSVS: Cal Diver III........... 8/87 115 1,320 105 18 -- -- ABS Cal Dive IV(1).......... 2000 120 1,440 60 24 -- -- ABS Mr. Jim................. 2/98 110 1,210 64 19 -- -- USCG Mr. Joe................. 1/99 100 1,035 46 16 -- -- USCG Mr. Jack................ 1/98 120 1,220 66 22 -- -- USCG OTHER: Sea Sorceress........... 8/97 374 8,600 10,000 50 -- -- DNV Cal Dive Barge I........ 8/90 150 NA 200 26 -- 200-ton ABS ROV..................... 4/97 25 -- -- -- -- -- --
- --------------- (1) Delivery of this vessel is expected in 2000. (2) Under government regulations and our insurance policies, we are required to maintain our vessels in accordance with standards of seaworthiness and safety set by government regulations and classification organizations. Those standards are set by various organizations such as American Bureau of Shipping ("ABS"), Det Norske Veritas ("DNV") and the Coast Guard. The ABS is one of several classification societies used by ship owners to certify that their vessels meet certain structural, mechanical and safety equipment standards, including Lloyd's Register, Bureau Veritas and DNV among others. 14 17 We incur routine drydock inspection, maintenance and repair costs under Coast Guard Regulations and to maintain ABS or DNV classification for our vessels. In addition to complying with these requirements, we have our own vessel maintenance program which management believes permits us to continue to provide our customers with well maintained, reliable vessels. In the normal course of our operations, we also charter other vessels on a short-term basis, such as tugboats, cargo barges, utility boats and dive support vessels. All of our vessels are subject to ship mortgages. SUMMARY OF NATURAL GAS AND OIL RESERVE DATA The table below sets forth information, as of December 31, 1999, with respect to our estimated net proved reserves and the present value of estimated future net cash flows at such date, based on estimates by Miller & Lents.
TOTAL PROVED (DOLLARS IN THOUSANDS) ------------ Estimated Proved Reserves: Natural Gas (MMcf)........................................ 25,381 Oil and Condensate (MBbls)................................ 1,702 Standardized measure of discounted future net cash flows (pre-tax)................................................. $37,852 -------
- --------------- (1) Six (6) blocks purchased in February of 2000 are not included in the above December 31, 1999 summary. As a result of this purchase, ERT's Estimated Proven Reserves have increased approximately 24% to 31,560 Mmcf of natural gas and 1,702 MBbls of oil and the standardized measure of discounted future net cash flow has increased to $39,827 (pre-tax). (2) The standardized measure of discounted future net cash flows attributable to our reserves was prepared using constant prices as of the calculation date, discounted at 10% per annum. As of March 24, 2000, we owned an interest in 137 gross (105 net) natural gas wells and 74 gross (51 net) oil wells located in federal offshore waters in the Gulf of Mexico. FACILITIES Our headquarters is at 400 N. Sam Houston Parkway E., in Houston, Texas. Our primary subsea and marine services operations are based in Morgan City, Louisiana. All of our facilities are leased. PROPERTY AND FACILITIES SUMMARY
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 Lafayette, Louisiana (Aquatica, Inc.)............................. Operations 8 acres Warehouse 12,000 square feet Offices 5,500 square feet
We also have sales offices in Lafayette and Harvey, Louisiana. 15 18 ITEM 3. LEGAL PROCEEDINGS. Our operations are subject to the inherent risks of offshore marine activity, including accidents resulting in personal injury and the loss of life or property, environmental mishaps, mechanical failures and collisions. We insure against these risks at levels consistent with industry standards. We believe our insurance is adequate to protect us against, among other things, the cost of replacing the total or constructive total loss of our vessels. We also carry workers' compensation, maritime employer's liability, general liability and other insurance customary in our business. All insurance is carried at levels of coverage and deductibles that we consider financially prudent. Our services are provided in hazardous environments where accidents involving catastrophic damage or loss of life could result, and litigation arising from such an event may result in our being named a defendant in lawsuits asserting large claims. To date, we have been involved in no such catastrophic claim or lawsuit. Although there can be no assurance that the amount of insurance we carry is sufficient to protect us fully in all events, management believes that our insurance protection is adequate for our business operations. A successful liability claim for which we are underinsured or uninsured could have a material adverse effect on our business. We are involved in various legal proceedings primarily involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act as a result of alleged negligence. In addition, we from time to time incur other claims, such as contract disputes, in the normal course of business. In that regard, CDI entered into a subcontract with Seacore Marine Contractors Limited to provide the Sea Sorceress for the excavation of glory holes in Canada. Due to unforeseen difficulties with respect to the sea states and soil conditions the contract was terminated. Seacore was provided a performance bond of $5 million with respect to the subcontract. No call has been made on this bond and Seacore and CDI believe the contract was wrongfully terminated and are vigorously defending this claim and seeking damages in arbitration. We believe that the outcome of this and all other such proceedings, even if determined adversely, would not have a material adverse effect on our business or financial condition. ITEM 4. SUBMISSION OF MAKERS TO A VOTE OF SECURITY HOLDERS. None. ITEM (UNNUMBERED). EXECUTIVE OFFICERS OF THE COMPANY The following table sets forth certain information as of December 31, 1999 with respect to the executive officers and certain other senior officers of the Company:
NAME AGE POSITION WITH THE COMPANY - ---- --- ------------------------- Owen Kratz............................ 46 Chairman and Chief Executive Officer Martin R. Ferron...................... 43 President and Chief Operating Officer S. James Nelson, Jr. ................. 57 Executive Vice President and Chief Financial Officer Andrew C. Becher...................... 54 Senior Vice President, General Counsel and Secretary Louis L. Tapscott..................... 62 Senior Vice President -- Special Projects Kenneth Duell......................... 48 Senior Vice President -- Business Development Lyle K. Kuntz......................... 48 President, Energy Resource Technology, Inc. Prentiss A. (Sonny) Freeman........... 52 President, Aquatica A. Wade Pursell....................... 35 Vice President -- Finance
Owen Kratz has served as our Chairman since May of 1998, Chief Executive Officer since April 1997, President since 1993 and Chief Operating Officer and director since 1990. He joined the Company in 1984 and has held various offshore positions, including SAT diving supervisor, and management responsibility for client relations, marketing and estimating. From 1982 to 1983, Mr. Kratz was the owner of an independent marine 16 19 construction company operating in the Bay of Campeche. Prior to 1982, he was a supervisor for various international diving companies and a SAT diver in the North Sea. Martin R. Ferron became President in February of 1999, has served as Chief Operating Officer since January 1998 and has been a Director since 1998. Mr. Ferron has twenty years of worldwide experience in the oilfield industry, seven of which were in senior management positions with international operations of McDermott Marine Construction and Oceaneering International Services Limited. Mr. Ferron has a Civil Engineering degree, a Masters Degree in Marine Technology, an MBA and is a Chartered Civil Engineer. S. James Nelson, Jr., has served as Executive Vice President and Chief Financial Officer and Director of the Company since 1990. From 1985 to 1988, Mr. Nelson was the Senior Vice President and Chief Financial Officer of Diversified Energies, Inc., the former parent of Cal Dive, at which time he had corporate responsibility for the Company. From 1980 to 1985, Mr. Nelson served as Chief Financial Officer of Apache Corporation, an oil and gas exploration and production company. From 1966 to 1980, Mr. Nelson was employed with Arthur Andersen & Co., and from 1976 to 1980, he was a partner serving on the firm's worldwide oil and gas industry team. Mr. Nelson received his undergraduate degree from Holy Cross College (B.S.) in 1964 and a masters in business administration (M.B.A.) from Harvard University in 1966. Andrew C. Becher has served as Senior Vice President, General Counsel and Secretary of the Company since January 1996. Mr. Becher served as outside general counsel for the Company from 1990 to 1996, while a partner with the national law firm Robins, Kaplan, Miller & Ciresi. From 1987 to 1990, Mr. Becher served as Senior Vice President of Dain Raucher, Inc., a regional investment banking firm. From 1976 to 1987, he was a partner specializing in mergers and acquisitions with the law firm of Briggs & Morgan in Minneapolis. Louis L. Tapscott joined the Company as Senior Vice President in August 1996. From 1992 to 1996, he was a Senior Vice President for Sonsub International, Inc., a company which operates a Deepwater fleet of ROVs. From 1984 to 1988, he was a director and Chief Operating Officer of Oceaneering International, Inc. Mr. Tapscott has over thirty years of executive management and operational experience working with subsea contractors and subsea technology organizations in the United States and internationally. Kenneth Duell joined Cal Dive in November of 1994 and was appointed Senior Vice President -- Business Development in 1997. From 1989 to 1994, he was employed by ABB Soimi, Milan, Italy, in connection with a modular refining systems development in Central Asia. From 1974 to 1988, he held various positions with Santa Fe International, including the ROV and diving division. Mr. Duell has over 22 years of worldwide experience in all aspects of the onshore and offshore construction and diving industry. Lyle Kuntz has served as President of our subsidiary, Energy Resource Technology, Inc., since its inception in 1992. Prior to forming ERT, Mr. Kuntz spent 17 years with ARCO Oil and Gas Co. in a broad range of senior engineering and management positions. A. Wade Pursell joined the Company in May 1997 as Vice President-Finance and Chief Accounting Officer. From 1988 through 1997 he was with Arthur Andersen LLP, most recently as an Experienced Manager specializing in the offshore services industry. Mr. Pursell is a Certified Public Accountant. Prentiss A. (Sonny) Freeman became President of Aquatica in October of 1997. Mr. Freeman has more than thirty years of experience in the Gulf of Mexico oilfield service industry, twenty-two of which have been in senior management and sales roles including twelve years as chief operating officer of American Oilfield Divers (now part of Stolt Offshore). In 1997 he purchased Acadiana Divers which changed its name to Aquatica and in 1999 sold Aquatica to CDI where he retained his role as its President. 17 20 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS. Our Common Stock is traded in the U.S. on the Nasdaq National Market ("Nasdaq"). The Common Stock is quoted through Nasdaq under the symbol "CDIS." The following table represents for the periods indicated, the high and low closing sales price per share of our Common Stock:
HIGH LOW ----------- ----------- Fiscal Year 1997 Third quarter(1).......................................... $ 37.75 $ 19.75 Fourth quarter............................................ 38.00 22.25 Fiscal Year 1998 First quarter............................................. $ 33.00 $ 23.25 Second quarter............................................ 39.375 26.00 Third quarter............................................. 28.125 12.25 Fourth quarter............................................ 22.6875 12.00 Fiscal Year 1999 First quarter............................................. $ 22.00 $ 14.25 Second quarter............................................ 32.6875 22.75 Third quarter............................................. 38.00 29.625 Fourth quarter............................................ 37.6875 20.00 Fiscal Year 2000 First quarter (through March 29, 2000).................... $51.0625 $31.5938
- --------------- (1) We completed our initial public offering on July 7, 1997 and trading information in the third quarter of 1997 is reported only after that date. As of March 24, 2000 there were approximately 2,400 holders of record of Common Stock. We have never paid cash dividends on its Common Stock and do not intend to pay cash dividends in the foreseeable future. We currently intend to retain earnings, if any, for the future operation and growth of our business. Certain of our financing arrangements restrict the payment of cash dividends under certain circumstances. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources". In July of 1999, we issued 696,380 shares of common stock pursuant to Section 4(2) of the Securities Act of 1933 in connection with the acquisition of our subsidiary Aquatica. 18 21 ITEM 6. SELECTED FINANCIAL DATA The financial data presented below for each of the five years ended December 31, 1999, should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and Notes to Consolidated Financial Statements included elsewhere in this Form 10-K.
YEAR ENDED DECEMBER 31, -------------------------------------------------- 1995 1996 1997 1998 1999 ------- ------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net Revenues.............................. $37,524 $76,122 $109,386 $151,887 $160,954 Gross Profit.............................. 8,849 22,086 33,685 49,209 37,251 Net Income................................ 2,674 8,435 14,482 24,125 16,899 Net Income Per Share: Basic................................... 0.24 0.76 1.12 1.66 1.13 Diluted................................. 0.24 0.75 1.09 1.61 1.10 EBITDA.................................... 6,650 19,017 29,916 45,544 44,805 Total Assets.............................. 44,859 83,056 125,600 164,235 243,722 Working Capital........................... 4,033 13,409 28,927 45,916 38,887 Long-Term Debt............................ 5,300 25,000 -- -- -- Shareholders' Equity...................... 22,408 30,844 89,369 113,643 150,872
19 22 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Natural gas and oil prices, the offshore mobile rig count and Gulf of Mexico lease activity are three of the primary indicators management uses to predict the level of the Company's business. CDI's construction services generally follow successful drilling activities by six to eighteen months on the Continental Shelf and twelve months or longer in the Deepwater arena. The level of drilling activity is related to both short and long-term trends in natural gas and oil prices. Commodity prices declined significantly in the last half of 1998 and early 1999 resulting in the utilization of offshore mobile rigs dropping to approximately 70% in contrast to almost full utilization in 1997 and the first half of 1998. This trend began reversing in the second quarter of 1999 such that oil prices have recently reached their highest level since the Gulf War and natural gas prices are hovering in a range of $2.60/MCF to $2.80/MCF. However, E&P companies have been hesitant to ramp up spending and accordingly demand for the Company's services remained relatively soft throughout 1999. Product prices impact the Company's natural gas and oil operations in several respects. The Company seeks to acquire producing natural gas and oil properties that are generally in the later stages of their economic life. These properties typically have few, if any, unexplored drilling locations, so the potential abandonment liability is a significant consideration with respect to the offshore properties which the Company has purchased to date. Although higher natural gas prices tend to reduce the number of mature properties available for sale, these higher prices contributed to improved operating results for the Company in 1996, 1997 and the second half of 1999. In contrast, lower natural gas prices, as experienced in 1998 and early 1999, contributed to lower operating results for ERT in those periods and generally increased the number of mature properties acquired during those periods. Salvage operations consist of platform decommissioning, removal and abandonment and P&A services performed by the Company's salvage assets, i.e., a stiff-leg derrick barge and well servicing equipment. In addition, salvage related support, such as debris removal and preparation of platform legs for removal, is often provided by the Company's surface diving vessels. In 1989, management targeted platform removal and salvage operations as a regulatory driven activity which offers a partial hedge against fluctuations in the commodity price of natural gas. In particular, MMS regulations require removal of platforms within twelve months after lease expiration and also require remediation of the seabed at the well site to its original state. The Company contracts and manages, on a turnkey basis, all aspects of the decommissioning and abandonment of fields of all sizes using third party heavy lift derrick barges if necessary. The Company also has an alliance with Horizon Offshore gaining access to expanded derrick barge and pipelay capacity. In 1999, CDI launched a new full field development product line to assist cash constrained customers on the OCS. With 4,000 platforms and production facilities already in place in the Gulf our underlying premise is that each new field need not be re-engineered. Adapting industry standard designs we now stock subsea trees, prefabricated modules, well panels and controls and umbilicals for immediate assembly. That led to five full field/pipelay projects in 1999. 20 23 The following table sets forth for the periods presented (i) average U.S. natural gas prices, (ii) the Company's natural gas production, (iii) the average number of offshore rigs under contract in the Gulf of Mexico, (iv) the number of platforms installed and removed in the Gulf of Mexico and (v) the vessel utilization rates for each of the major categories of the Company's fleet.
1997 1998 1999 ----------------------------- ----------------------------- ----------------------------- Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- U.S. Natural Gas Prices(1)........ $2.67 $2.13 $2.46 $2.88 $2.18 $2.26 $2.03 $1.92 $1.80 $2.22 $2.53 $2.45 ERT Gas and Oil Production (MMCFe)......................... 1,519 1,213 1,381 1,252 1,595 1,252 901 1,155 1,488 1,803 2,777 2,786 Rigs Under Contract in the Gulf of Mexico(2)....................... 165 169 168 169 170 167 149 137 121 115 126 146 Platform Installations(3)......... 16 21 29 39 18 16 21 20 12 13 13 16 Platform Removals(3).............. 3 21 31 28 3 15 24 8 2 20 40 15 Average Company Vessel Utilization Rate:(4) Dynamic Positioned.............. 60% 79% 92% 94% 75% 64% 85% 80% 70% 49% 82% 69% Saturation DSV.................. 58% 77% 81% 77% 88% 79% 70% 83% 54% 69% 79% 65% Surface Diving.................. 53% 80% 90% 81% 33% 58% 72% 76% 63% 69% 78% 51% Derrick Barge................... 22% 78% 99% 89% 28% 73% 70% 70% 40% 68% 83% 50%
- --------------- (1) Average of the monthly Henry Hub cash prices in $ per Mcf, as reported in Natural Gas Week. (2) Average monthly number of rigs contracted, as reported by Offshore Data Services. (3) Source: Offshore Data Services; installation and removal of platforms with two or more piles in the Gulf of Mexico. (4) Average vessel utilization rate is calculated by dividing the total number of days the vessels in this category generated revenues by the total number of days in each quarter (excluding Aquatica in 1999). Vessel utilization is historically lower during the first quarter due to winter weather conditions in the Gulf of Mexico. Accordingly, the Company plans its drydock inspections and other routine and preventive maintenance programs during this period. During the first quarter, a substantial number of the Company's customers finalize capital budgets and solicit bids for construction projects. During the second quarter of 1999, the Uncle John spent 30 days in drydock undergoing thruster work and DNV inspections. The bid and award process during the first two quarters leads to the commencement of construction activities during the second and third quarters. As a result, the Company has historically generated more than 50% (up to 65%) of its consolidated revenues in the last six months of the year. The Company's operations can also be severely impacted by weather during the fourth quarter. The Company's salvage barge, which has a shallow draft, is particularly sensitive to adverse weather conditions, and its utilization rate will be lower during such periods. To minimize the impact of weather conditions on the Company's operations and financial condition, CDI began operating DP vessels and expanded into the acquisition of mature offshore properties. The unique station-keeping ability offered by dynamic positioning enables these vessels to operate throughout the winter months and in rough seas. Operation of natural gas and oil properties tends to offset the impact of weather since the first and fourth quarters are typically periods of high demand for natural gas and of strong natural gas prices. Due to this seasonality, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters. 21 24 RESULTS OF OPERATIONS Comparison of Year Ended December 31, 1999 to Year Ended December 31, 1998 Revenues. Consolidated revenues of $161 million in 1999 were 6% more than the $151.9 million in 1998 with natural gas and oil production providing all of the increase while Subsea operations revenues declined $10.9 million. Most of this decline is due to 1998 revenues including $8 million from the charter of two Coflexip Stena Offshore vessels. One project in 1999 (Cooper abandonment for EEX) represented 13% of consolidated revenues. Adding the Cal Dive Aker Dove in September 1999 and acquiring the remaining 55% of Aquatica, Inc., in August 1999 (and thus consolidating their results from that date forward) added $10 million to 1999 revenues, while the subcontracting of derrick and pipelay barges also added $10 million in 1999, offsetting the shortfall created by stacking the Balmoral Sea nearly the entire first half of 1999. Natural gas and oil production was $32.5 million in 1999 as compared to $12.6 million in 1998. The increase was due mainly to a rise in production from 4.9 BCFE (billion of cubic feet equivalent) to 8.9 BCFE in 1999 as the number of blocks owned by ERT was essentially doubled through property acquisitions during the first four months of 1999. 1999 revenues were also assisted by improved average gas prices ($2.35/MCF compared to $2.12 in 1998), an increase in oil production and prices and the sale of three offshore leases. Gross Profit. Gross profit decreased by $12 million, or 24%, from $49.2 million in 1998 to $37.3 million in 1999 despite an $8.4 million increase in natural gas and oil production gross profit. The decrease in Subsea and Salvage gross profit of $20.4 million is due to the $10.9 million revenue decline discussed above coupled with margins declining from 33% in 1998 to 20% in 1999. In addition to a decline in demand for CDI's services on the OCS in 1999 compared to 1998, the primary reason for the margin decline was CDI's shift to prime contractor on eight major projects during 1999 which include high third party pass through costs (such costs were 31% of revenues in 1999 compared to 23% in 1998). Natural gas and oil production gross profit was $11.9 million in 1999 as compared to $3.5 million in the prior year. The increase was due to the aforementioned production improvement, gas and oil price increases and the gain recorded on the sale of certain offshore blocks during 1999 offset by the writedown of the carrying value of three ERT fields in connection with the 1999 Well Exploitation Program. Selling and Administrative Expenses. Selling and administrative expenses decreased $2.6 million in 1999 to $13.2 million as compared to $15.8 million in 1998. The primary reason for the decline was the lack of Subsea group bonuses and staff reductions effected early in 1999. Consolidation of Aquatica the final five months of 1999 added $1.2 million. SG&A for 1999 includes $3.7 million related to ERT, an increase of $2.2 million over 1998 as we added new people to handle the expansion in operations. That subsidiary's significantly increased income also triggered significantly higher bonus payments under its incentive program. Selling and administrative costs were 8% of revenues in 1999, two margin points better than the 10% achieved in 1998. Other Income and Expenses. The Company recorded $600,000 in 1999 for its share of earnings in Aquatica, Inc., compared to $2.6 million in 1998 as beginning August 1, 1999 Aquatica's results were consolidated with CDI's as a result of the Company's acquisition of the remaining 55% ownership in Aquatica. Net interest income of $849,000 was comparable to the $1.1 million earned in 1998 as CDI remained relatively debt free throughout both years. Income Taxes. Income taxes were $8.5 million in 1999 compared to $13 million in 1998 due to the decreased profitability. The effective tax rate fell from 35% in 1998 to 33% in 1999 due to research and development credits realized as a result of CDI's operating at the forefront of Deepwater technology. Net income. Net income decreased 30% in 1999 compared to 1998 as a result of factors described above. Diluted earnings per share decreased slightly more as a result of the additional shares issued in the Aquatica acquisition. 22 25 Comparison of Year Ended December 31, 1998 to Year Ended December 31, 1997 Revenues. Consolidated revenues of $151.9 million in 1998 were 39% more than the $109.4 million earned during 1997 with the Subsea operations contributing all of the increase while natural gas and oil production revenues declined $3.9 million. All of the increase was due to increased demand for services provided by CDI's DP vessels, particularly the Uncle John, Witch Queen and Balmoral Sea which together contributed 62% of the increase. In addition, new vessels (Sea Sorceress and Merlin) contributed $10.3 million of the increase. The charter of two Coflexip Stena Offshore vessels, the Marianos during the first quarter and the Constructor in the second, added $8.0 million to the 1998 revenues. Natural gas and oil revenues were $12.6 million in 1998 as compared to $16.5 million in 1997. The decrease was due to a decline in production from 5.7 BCFE during 1997 to 4.9 BCFE in 1998 and a decline in average gas prices from $2.57/Mcf for 1997 to $2.12/Mcf during 1998. The decline in production is a result of five wells going off line in the second quarter and remedial work being delayed into the fourth quarter by a lack of equipment and then by weather. Gross Profit. Gross profit increased by $15.5 million, or 46%, from $33.7 million in 1997 to $49.2 million in 1998 with the Uncle John, Witch Queen and Balmoral Sea making up the majority of the increase. The remaining increase was due to improved demand for the two saturation diving vessels and the vessels which work in the shallow Gulf of Mexico (from the shore to 300 feet of water). Subsea and salvage margins increased from 27% in 1997 to 33% during 1998 due mainly to outstanding offshore performance and demand for the DP vessels. Natural gas and oil production gross profit was $3.5 million in 1998 as compared to $8.4 million in the prior year. The decrease was due to the aforementioned declines in average natural gas prices and production during 1998 as compared to 1997 and to expensive efforts to re-establish production in the second half of the year. Selling and Administrative Expenses. Selling and administrative expenses increased $4.6 million to $15.8 million in 1998 as compared to 1997. The $15.8 million includes a $4.5 million provision principally for 1998 incentive compensation compared to $2.9 million provided in 1997. The remainder of the increase is due to the addition of new personnel to support the Company's Deepwater strategy, growth in it base business and to the cost of a supply chain management consulting project. Selling and administrative costs were 10% of revenues in 1998, a level identical to that in 1997. Other Income and Expenses. The Company recorded $2.6 million in 1998 reflecting its share of earnings of Aquatica, Inc. Net interest income and other of $1.1 million for 1998 compares to $208,000 of net interest expense and other for 1997. This improvement was due to the Company remaining debt free since completion of its initial public offering of common stock in July, 1997. Income Taxes. Income taxes were $13 million in 1998 as compared to $7.8 million for the prior year. The increase was due to the Company's increased profitability as the effective tax rate remained 35% in both years. Roughly 35% of the 1998 tax provision was deferred due mainly to increased depreciation in addition to the Company's Deepwater research and development efforts. Net Income. Net income increased 67% to $24.1 million in 1998 as compared to $14.5 million in 1997 as a result of factors described above. Diluted earnings per share increased 48% (19 percentage points less than the net income increase) in 1998, as compared to 1997, due to the impact on weighted average common shares outstanding of the new shares issued in the July 1997 IPO. LIQUIDITY AND CAPITAL RESOURCES The Company has historically funded its operating activities principally from internally generated cash flow, even during industry-depressed years such as 1992 and 1998/1999. An initial public offering of common stock was completed on July 7, 1997, with the sale of 2,875,000 shares generating net proceeds to the Company of approximately $39.5 million, net of underwriting discounts and issuance costs. The proceeds were used to fund capital expenditures during 1997, and to repay all outstanding long-term indebtedness. As of 23 26 December 31, 1999, the Company had $38.9 million of working capital (including $20.0 million of cash on hand) and no debt outstanding after funding the equity investment in Aquatica and $14.9 million of capital expenditures in 1998 and $77.4 million of capital expenditures in 1999, which includes ERT's purchase of 26 blocks offshore, $31 million of construction costs for the Q4000 and $18.9 million for the acquisition of 56% interest in the Cal Dive Aker Dove (which was subsequently sold in a sale/leaseback transaction). Subsequent to year end CDI's cash on hand increased to $22 million at February 29, 2000 after funding ERT's acquisition of six offshore blocks from EEX. Additionally, CDI has approximately $40 million available under a Revolving Credit Agreement. Operating Activities. Net cash provided by operating activities was $25.5 million in 1999, as compared to $35.7 million provided in 1998. This decrease is primarily the result of decreased profitability of the Company and the level of funding required to fund the increases in accounts receivable ($16.9 million required in 1999 compared to $900,000 returned in 1998) which occurred primarily as a result of the terms negotiated with EEX for the Cooper abandonment project. Pursuant to those terms, $22 million was paid in January 2000. In addition, depreciation and amortization increased as a result of natural gas and oil properties acquisitions along with the write down of carrying value of three ERT fields in 1999 discussed below. The Company experienced an increase in the level of funding from accounts payable and accrued liabilities of $15.7 million in 1999 compared to 1998. The increase relates primarily to accruals with respect to the Q4000 construction project and the EEX project. Net cash provided by operating activities was $35.7 million in 1998, as compared to $22.3 million provided in 1997. This increase was primarily the result of increased profitability and a decline in the level of funding required to fund accounts receivable increases ($5.8 million required in 1997 compared to $900,000 returned in 1998). Other current assets increased $4.2 million at December 31, 1998 as compared to December 31, 1997 due mainly to the purchases of materials and supplies for the start up of the Full Field Development program. In addition, depreciation and amortization increased as a result of vessel and natural gas and oil properties acquisitions. The Company experienced improved collections of its accounts receivable during 1998 as compared to the prior year. Total accounts receivable decreased $900,000 at December 31, 1998 as compared to December 31, 1997 while revenues grew 39% in 1998 compared to 1997. The Company's average number of days to bill and collect its trade receivables decreased by 10 days in 1998 as compared to 1997. Investing Activities. Capital expenditures have consisted principally of strategic asset acquisitions, the assembly of a fleet of DP vessels, including the Witch Queen, Balmoral Sea, Uncle John, Sea Sorceress, Merlin and Cal Dive Aker Dove, improvements to existing vessels and the acquisition of offshore natural gas and oil properties. The Company has consistently targeted the year 2001 as the time when we will see a significant acceleration in Deepwater demand. As a result, 1999 capital expenditures of $77.4 million were over five times the prior year. This figure includes $31 million for the construction of the Q4000, the acquisition of Hvide Marine's interest in Cal Dive Aker, CAHT I, LLC, the Company which leases the Cal Dive Aker Dove (a newbuild DP anchor handling and subsea construction vessel) ($18.9 million) as well as the purchase of new engines for the Uncle John. ERT internally funded $17 million of capital expenditures from the proceeds of the sale of offshore properties and the repayment of deferred lease abandonment costs received in one acquisition. During the first four months of 1999, in four separate transactions, ERT acquired interests in 20 blocks in exchange for cash consideration, as well as assumption of the pro rata share of the related decommissioning liabilities. During 1998, ERT acquired net working interests in six blocks involving two separate fields in exchange for cash as well as assumption of the pro rata share of the related decommissioning liability. In connection with 1999 and 1998 offshore property acquisitions, ERT assumed net abandonment liabilities estimated at approximately $19,500,000 and $3,432,000 respectively. During the third quarter of 1999, ERT substantially completed its 1999 Well Exploitation Program, which included five recompletions and which led to the sale of its interest in three offshore blocks. It is an operating policy that ERT will sell assets (offshore leases, platforms, compressors, etc.) when the expected 24 27 future revenue stream can be accelerated in a single transaction. Accordingly, proceeds received from such transactions are recorded as revenue in the period received. These sales were structured as Section 1031 "Like Kind" exchanges for tax purposes. Accordingly, the cash received was restricted to use for subsequent acquisitions of additional natural gas and oil properties which, as discussed below, occurred in the first quarter of 2000. Since inception ERT has acquired interests in 41 offshore leases, sold seven (two in 1997 and two in 1998), and taken one field full cycle to decommissioning. The well exploitation work completed during the third quarter also enabled ERT to assess and write down the carrying value of three ERT fields, including one where a third party vendor damaged the reservoir formation. The net result of the sales and the 1999 Well Exploitation Program was to add approximately thirteen cents to 1999 diluted earnings per share. During the first quarter 2000 ERT acquired interests in six offshore blocks from EEX Corporation and agreed to operate the remaining EEX properties on the Outer Continental Shelf (OCS). The acquired offshore blocks include working interests from 40% to 75% in five platforms, one caisson and 13 wells currently producing 23 mmcf per day (13 mmcf net). ERT exchanged cash of $4.9 million and assumed EEX's prorated share of the abandonment obligation for the acquired interests, and entered into a two-year contract to manage the remaining EEX operated properties. EEX personnel who operated these properties also became ERT employees. This acquisition was funded by restricted cash obtained from "Like Kind" sales and accordingly, the gain for the sale was deferred for tax purposes. Since 1993, including the transactions closed subsequent to year end, the Company has invested $43 million to acquire 47 offshore natural gas and oil leases. The Company records the amount of cash paid together with the abandonment liability assumed at the time such properties are acquired. Only the cash paid at closing is reflected in the Company's statement of cash flows together with bond and escrow deposits required in connection with these purchases. The Minerals Management Service requires operators in the Gulf of Mexico to post an areawide bond of $3 million. Beginning in 1998 the MMS allowed the Company to utilize an insurance carrier to provide such bonding. The Company has had, and anticipates having additional discussions with third parties regarding possible acquisitions (including natural gas and oil properties and vessels). However, the Company can give no assurance that any such transaction can be completed. In December, 1999, CAHT I entered into a sale-leaseback of the Cal Dive Aker Dove. Cal Dive's portion of the proceeds received totaled $20 million and resulted in a gain of $1.4 million which was deferred and is being amortized over the ten year term of the lease. The lease, which is accounted for as an operating lease, requires CAHT I to make quarterly payments of $988,000 and contains a renewal option and options to purchase the vessel for amounts approximating fair market value after 8 1/2 years of the lease term and at the end of the lease term. In February 1998, CDI purchased a significant minority equity interest in Aquatica, Inc., a surface diving company for $5 million. Effective August 1, 1999, 696,000 shares of common stock of Cal Dive were issued for all of the remaining common stock of Aquatica, Inc. This acquisition was accounted for as a purchase with the acquisition price being allocated to the assets acquired and liabilities assumed based upon their estimated fair values resulting in goodwill of $12 million which is being amortized over twenty-five years on a straight- line basis. Results of operations for Aquatica, Inc. are consolidated with those of Cal Dive for periods subsequent to August 1, 1999. The Company incurred $14.9 million of capital expenditures during 1998. In January 1998, ERT acquired interests in six blocks involving two separate fields from Sonat Exploration Company for cash and assumption of Sonat's pro rata share of the related decommissioning liability. The remaining balance includes costs associated with placing the Merlin in service and additions to the Sea Sorceress in preparation for the Terra Nova project as well as the cost of new steel and equipment added to the Witch Queen, Balmoral Sea and Cal Diver V during 1998 drydock inspections. Financing Activities. The Company has financed seasonal operating requirements and capital expenditures with internally generated funds, borrowings under credit facilities, the sale of Common Stock and the sale-leaseback transaction described above. The Revolving Credit Agreement, as amended, currently provides for a $40.0 million revolving line of credit. The Revolving Credit Agreement, which terminates in December 2000, is secured by trade receivables and mortgages on the Company's vessels. The Revolving Credit 25 28 Agreement prohibits the payment of dividends on the Company's capital stock and contains only one financial covenant (a fixed charge coverage ratio) and a limitation that debt not exceed $120 million. Interest on borrowings under the Revolving Credit Agreement is equal to Prime with incentive pricing thereafter pursuant to a formula based upon EBITDA (as defined therein). No borrowings were outstanding at December 31, 1999. Letters of credit are also available under the Revolving Credit Agreement which the Company typically uses if performance bonds are required or, in certain cases, in lieu of purchasing U.S. Treasury Bonds in conjunction with gas and oil property acquisitions. The only financing activity in 1999 and 1998 represents the exercise of employee stock options. Capital Commitments. In connection with its business strategy, management expects the Company to acquire or build additional vessels, acquire other assets, as well as seek to buy additional natural gas and oil properties. In July 1999, CDI's Board of Directors approved the construction of the Q4000, a newbuild, ultra-deepwater multi-service vessel, at a total estimated cost of $150 million. The Company recently received the "60 day letter" from the Maritime Administration regarding the application for Title XI financing for this semi-submersible vessel. The letter signifies that funding is available and that CDI has satisfactorily answered MARAD's technical questions relative to the vessel. If this financing transaction is approved, initial construction funding will be drawn in the second quarter of 2000. We expect to submit a supplemental appropriation of $20 million to $30 million to convert the Sea Sorceress to full DP or purchase an existing DP vessel having similar Deepwater construction features. Other than building, converting or buying DP vessels, management believes existing cash balances, the net cash generated from operations and available borrowing capacity under the Revolving Credit Agreement will be adequate to meet funding requirements for the next year. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK Not applicable because, at December 31, 1999, the Company was not engaged in any transactions requiring disclosure under this item. 26 29 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS
PAGE ---- Report of Independent Public Accountants.................... 28 Consolidated Balance Sheets -- December 31, 1999 and 1998... 29 Consolidated Statements of Operations for the years ended December 31, 1999, 1998 and 1997.......................... 30 Consolidated Statements of Shareholders' Equity for the years ended December 31, 1999, 1998 and 1997.............. 31 Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997.......................... 32 Notes to Consolidated Financial Statements.................. 33
27 30 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Cal Dive International, Inc.: We have audited the accompanying consolidated balance sheets of Cal Dive International, Inc. (a Minnesota corporation) and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of operations, shareholders' equity and cash flows for the three years in the period ended December 31, 1999. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cal Dive International, Inc., and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Houston, Texas February 17, 2000 28 31 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1999 AND 1998 (IN THOUSANDS)
DECEMBER 31, ------------------- 1999 1998 -------- -------- ASSETS Current assets: Cash and cash equivalents................................. $ 11,310 $ 32,380 Restricted Cash........................................... 8,686 463 Accounts receivable -- Trade, net of revenue allowance on gross amounts billed of $1,789 and $1,335.................................. 48,191 20,350 Unbilled revenue....................................... 3,430 10,703 Other current assets...................................... 16,327 9,190 -------- -------- Total current assets.............................. 87,944 73,086 -------- -------- Property and equipment...................................... 180,519 107,421 Less -- Accumulated depreciation.......................... (45,862) (28,262) -------- -------- 134,657 79,159 Other assets: Investment in Aquatica, Inc. ............................. -- 7,656 Goodwill.................................................. 13,792 -- Other assets, net......................................... 7,329 4,334 -------- -------- $243,722 $164,235 ======== ======== LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Accounts payable.......................................... $ 31,834 $ 15,949 Accrued liabilities....................................... 17,223 10,020 Income taxes payable...................................... -- 1,201 -------- -------- Total current liabilities......................... 49,057 27,170 -------- -------- Long-term debt.............................................. -- -- Deferred income taxes....................................... 16,837 13,539 Decommissioning liabilities................................. 26,956 9,883 Commitments and contingencies Shareholders' equity: Common stock, no par, 60,000 shares authorized, 22,395 and 21,402 shares issued................................... 73,311 52,981 Retained earnings......................................... 81,312 64,413 Treasury stock, 6,820 shares, at cost..................... (3,751) (3,751) -------- -------- Total shareholders' equity........................ 150,872 113,643 -------- -------- $243,722 $164,235 ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 29 32 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, ------------------------------ 1999 1998 1997 -------- -------- -------- Net revenues: Subsea and salvage........................................ $128,435 $139,310 $ 92,860 Natural gas and oil production............................ 32,519 12,577 16,526 -------- -------- -------- 160,954 151,887 109,386 Cost of sales: Subsea and salvage........................................ 103,113 93,607 67,538 Natural gas and oil production............................ 20,590 9,071 8,163 -------- -------- -------- Gross profit........................................... 37,251 49,209 33,685 Selling and administrative expenses......................... 13,227 15,801 11,196 -------- -------- -------- Income from operations...................................... 24,024 33,408 22,489 Equity in earnings of Aquatica, Inc. ..................... 600 2,633 -- Net interest (income) expense and other................... (849) (1,103) 208 -------- -------- -------- Income before income taxes.................................. 25,473 37,144 22,281 Provision for income taxes................................ 8,465 13,019 7,799 Minority Interest......................................... 109 -- -- -------- -------- -------- Net income........................................ $ 16,899 $ 24,125 $ 14,482 ======== ======== ======== Net income per share: Basic..................................................... $ 1.13 $ 1.66 $ 1.12 Diluted................................................... 1.10 1.61 1.09 ======== ======== ======== Weighted average common shares outstanding: Basic..................................................... 15,008 14,549 12,883 Diluted................................................... 15,327 14,964 13,313 ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 30 33 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 (IN THOUSANDS)
COMMON STOCK TREASURY STOCK TOTAL ---------------- RETAINED ---------------- SHAREHOLDERS' SHARES AMOUNT EARNINGS SHARES AMOUNT EQUITY ------ ------- -------- ------ ------- ------------- Balance, December 31, 1996......... 18,448 $ 9,093 $25,806 (7,349) $(4,055) $ 30,844 Net income......................... -- -- 14,482 -- -- 14,482 Activity in company stock plans.... 22 327 -- -- -- 327 Sale of treasury stock, net........ -- 4,055 -- 529 304 4,359 Sale of common stock, net.......... 2,875 39,357 -- -- -- 39,357 ------ ------- ------- ------ ------- -------- Balance, December 31, 1997......... 21,345 52,832 40,288 (6,820) (3,751) 89,369 Net income......................... -- -- 24,125 -- -- 24,125 Activity in company stock plans, net.............................. 57 149 -- -- -- 149 ------ ------- ------- ------ ------- -------- Balance, December 31, 1998......... 21,402 52,981 64,413 (6,820) (3,751) 113,643 Net income......................... -- -- 16,899 -- -- 16,899 Activity in company stock plans, net.............................. 297 4,174 -- 4,174 Acquisition of Aquatica, Inc. ..... 696 16,156 -- -- -- 16,156 ------ ------- ------- ------ ------- -------- Balance, December 31, 1999......... 22,395 $73,311 $81,312 (6,820) $(3,751) $150,872 ====== ======= ======= ====== ======= ========
The accompanying notes are an integral part of these consolidated financial statements. 31 34 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ------------------------------ 1999 1998 1997 -------- -------- -------- Cash flows from operating activities: Net income................................................ $ 16,899 $ 24,125 $ 14,482 Adjustments to reconcile net income to net cash provided by operating activities -- Depreciation and amortization.......................... 20,615 9,563 7,512 Deferred income taxes.................................. 4,298 4,469 3,789 Equity in earnings of Aquatica, Inc. .................. (600) (2,633) -- Gain on sale of gas and oil properties................. (8,454) (585) (464) Changes in operating assets and liabilities: Accounts receivable, net............................. (16,918) 937 (5,777) Other current assets................................. ( 6,468) (3,919) (2,653) Accounts payable and accrued liabilities............. 21,217 5,536 4,766 Income taxes payable, net............................ (430) 599 736 Other noncurrent, net................................ (4,660) (2,395) (97) -------- -------- -------- Net cash provided by operating activities......... 25,499 35,697 22,294 -------- -------- -------- Cash flows from investing activities: Capital expenditures...................................... (77,447) (14,886) (28,936) Restricted Cash........................................... (8,222) (463) -- Investment in Aquatica, Inc. ............................. 442 (5,023) -- Prepayment of Deferred Lease Abandonment Costs............ 7,750 -- Deposits restricted for salvage operations................ (66) 3,262 (436) Proceeds from sales of property........................... 28,931 619 1,084 -------- -------- -------- Net cash used in investing activities............. (48,612) (16,491) (28,288) -------- -------- -------- Cash flows from financing activities: Exercise of stock warrants and options, net............... 2,043 149 99 Sale of common stock, net of transaction costs............ -- -- 39,357 Sale of treasury stock, net of transaction costs.......... -- -- 4,359 Borrowings under term loan facility, net.................. -- -- 6,700 Repayments of long-term debt.............................. -- -- (31,700) -------- -------- -------- Net cash provided by financing activities......... 2,043 149 18,815 -------- -------- -------- Net increase (decrease) in cash and cash equivalents........ (21,070) 19,355 12,821 Cash and cash equivalents: Balance, beginning of year................................ 32,380 13,025 204 -------- -------- -------- Balance, end of year...................................... $ 11,310 $ 32,380 $ 13,025 ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements. 32 35 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION: Cal Dive International, Inc. (Cal Dive, CDI or the Company), headquartered in Houston, Texas, owns, staffs and operates fourteen marine construction vessels and a derrick barge in the Gulf of Mexico. The Company provides a full range of services to offshore oil and gas exploration and production and pipeline companies, including underwater construction, maintenance and repair of pipelines and platforms, and salvage operations. Diving and vessel support services in the shallow water market are provided by Aquatica, Inc., a wholly-owned subsidiary based in Lafayette, Louisiana. In September 1992, Cal Dive formed a wholly owned subsidiary, Energy Resource Technology, Inc. (ERT), to purchase producing offshore oil and gas properties which are in the later stages of their economic lives. ERT is a fully bonded offshore operator and, in conjunction with the acquisition of properties, assumes the responsibility to decommission the property in full compliance with all governmental regulations. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Principles of Consolidation The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated. Goodwill Goodwill is amortized on the straight-line method over its estimates useful life of 25 years. The Company continually evaluates whether subsequent events or circumstances have occurred that indicates the remaining useful life of goodwill may warrant revision or that the remaining balance of goodwill may not be recoverable. Management believes that there have been no events or circumstances which warrant revision to the remaining useful life or which affect recoverability of goodwill. Property and Equipment Property and equipment are recorded at cost. Depreciation is provided primarily on the straight-line method over the estimated useful lives of the assets. All of the Company's interests in natural gas and oil properties are located offshore in United States waters. The Company follows the successful efforts method of accounting for its interests in natural gas and oil properties. Under the successful efforts method, only the costs of successful wells and leases containing productive reserves are capitalized. ERT offshore property acquisitions are recorded at the value exchanged at closing together with an estimate of its proportionate share of the decommissioning liability assumed in the purchase based upon its working interest ownership percentage. In estimating the decommissioning liability assumed in offshore property acquisitions, the Company performs detailed estimating procedures, including engineering studies. All capitalized costs are amortized on a unit-of-production basis (UOP) based on the estimated remaining oil and gas reserves. Properties are periodically assessed for impairment in value, with any impairment charged to expense. 33 36 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following is a summary of the components of property and equipment (dollars in thousands):
ESTIMATED USEFUL LIFE 1999 1998 ----------- -------- -------- Vessels.............................................. 15 $ 85,397 $ 72,220 Offshore leases and equipment........................ UOP 49,037 22,530 Construction in Progress............................. N/A 31,341 -- Machinery, equipment and leasehold improvements...... 5 14,744 12,671 -------- -------- Total property and equipment............... $180,519 $107,421 ======== ========
In July 1999, the CDI Board of Directors approved the construction of the Q4000, a newbuild, ultra-deepwater multi-purpose vessel, for a total estimated cost of $150 million. Amounts incurred on this project through the end of 1999 are included in Construction in Progress. The cost of repairs and maintenance of vessels and equipment is charged to operations as incurred, while the cost of improvements is capitalized. Total repair and maintenance charges were $6,031,000, $8,264,000 and $6,771,000 for the years ended December 31, 1999, 1998 and 1997, respectively. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Earnings Per Share The Company computes and presents earning per share in accordance with Statement of Financial Accounting Standard No. 128, "Earnings Per Share". SFAS 128 requires the presentation of "basic" EPS and "diluted" EPS on the face of the statement of operations. Basic EPS is computed by dividing the net income available to common shareholders by the weighted-average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS except that the denominator includes dilutive common stock equivalents, which were stock options, less the number of treasury shares assumed to be purchased from the proceeds from the exercise of stock options. Revenue Recognition The Company earns the majority of its service revenues during the summer and fall months. Revenues are derived from billings under contracts (which are typically of short duration) that provide for either lump-sum turnkey charges or specific time, material and equipment charges which are billed in accordance with the terms of such contracts. The Company recognizes revenue as it is earned at estimated collectible amounts. Revenue on significant turnkey contracts is recognized on the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in the period such losses are determined. Unbilled revenue represents revenue attributable to work completed prior to year-end which has not yet been invoiced. All amounts included in unbilled revenue at December 31, 1999 are expected to be billed and collected within one year. 34 37 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Revenue Allowance on Gross Amounts Billed The Company bills for work performed in accordance with the terms of the applicable contract. The gross amount of revenue billed will include not only the billing for the original amount quoted for a project but also include billings for services provided which the Company believes are outside the scope of the original quote. The Company establishes a revenue allowance for these additional billings based on its collections history if conditions warrant such a reserve. Major Customers and Concentration of Credit Risk The market for the Company's services is the offshore oil and gas industry. Oil and gas companies make capital expenditures on exploration, drilling and production operations offshore, the level of which is generally dependent on the prevailing view of the future oil and gas prices, which have been characterized by significant volatility in recent years. The Company's customers consist primarily of major, well-established oil and pipeline companies and independent oil and gas producers. The Company performs ongoing credit evaluations of its customers and provides allowances for probable credit losses when necessary. The percent of consolidated revenue of major customers was as follows: 1999 -- EEX Corporation (13%); 1998 -- Chevron USA (11%); and 1997 -- Shell Oil Co. (11%) and -- J. Ray McDermott, S.A. (19%). Income Taxes Deferred taxes are recognized for revenues and expenses reported in different years for financial statement purposes and income tax purposes in accordance with SFAS No. 109, "Accounting for Income Taxes." The statement requires, among other things, the use of the liability method of computing deferred income taxes. The liability method is based on the amount of current and future taxes payable using tax rates and laws in effect at the balance sheet date. Deferred Drydock Charges Effective January 1, 1998, the Company changed its method of accounting for regulatory (U.S. Coast Guard, American Bureau of Shipping and Det Norske Veritas) related drydock inspection and certification expenditures. This change was made due to the significant changes in the composition of the Company's fleet which has been expanded to include more sophisticated dynamically positioned vessels that are capable of working in the Deepwater Gulf of Mexico, a key to Cal Dive's operating strategy. The Company previously expensed inspection and certification costs as incurred; however, effective January 1, 1998, such expenditures are being capitalized and amortized over the 30-month period between regulatory mandated drydock inspections and certification. This predominant industry practice provides better matching of expenses with the period benefitted (i.e., certification to operate the vessel for a 30-month period between required drydock inspections and to meet bonding and insurance coverage requirements). This change had a $765,000 positive impact on net income, or $0.05 per share, in the Company's 1998 consolidated financial statements. Statement of Cash Flow Information The Company defines cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of less than three months. During the years ended December 31, 1999, 1998 and 1997, the Company's cash payments for interest expense were approximately $-0-, $-0- and $1,033,000 respectively, and cash payments for federal income taxes were approximately $4,075,000, $7,650,000 and $3,200,000 respectively. 35 38 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Reclassifications Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes to make them consistent with the current presentation format. 3. ACQUISITION OF AQUATICA, INC.: In February 1998, CDI purchased a significant minority equity interest in Aquatica, Inc., a surface diving company. CDI accounted for this investment on the equity basis of accounting for financial reporting purposes. The related Shareholder Agreement provided that the remaining shares of Aquatica, Inc. could be converted into Cal Dive shares based on a formula which, among other things, values their shares of Aquatica, Inc. and must be accretive to Cal Dive shareholders. Effective August 1, 1999, 696,000 shares of common stock of Cal Dive were issued for all of the remaining common stock of Aquatica, Inc. pursuant to these terms. This acquisition was accounted for as a purchase with the acquisition price of $16.2 million being allocated to the assets acquired and liabilities assumed based upon their estimated fair values. The fair value of tangible assets acquired and liabilities assumed was $6.4 million and $2.2 million, respectively. The balance of the purchase price ($12 million) was recorded as excess of cost over net assets acquired (goodwill). Accumulated amortization as of December 31,1999 was $300,000. Results of operations for Aquatica, Inc. are consolidated with those of Cal Dive for periods subsequent to August 1, 1999. 4. OFFSHORE PROPERTY TRANSACTIONS: During the first four months of 1999, in four separate transactions, ERT acquired interests in 20 blocks in exchange for cash consideration, as well as assumption of the pro rata share of the related decommissioning liabilities. During 1997, ERT acquired net working interests of 50 percent to 100 percent in 3 offshore blocks and in 1998, interests in six blocks involving two separate fields in exchange for cash as well as assumption of the pro rata share of the related decommissioning liability. In connection with 1999, 1998 and 1997 offshore property acquisitions, ERT assumed net abandonment liabilities estimated at approximately $19,500,000, $3,432,000 and $1,351,000 respectively. ERT production activities are regulated by the federal government and require significant third-party involvement, such as refinery processing and pipeline transportation. The Company records revenue from its offshore properties net of royalties paid to the Minerals Management Service ("MMS"). Royalty fees paid totaled approximately $4,017,000, $2,031,000 and $3,018,000 for the years ended 1999, 1998 and 1997, respectively. In accordance with federal regulations that require operators in the Gulf of Mexico to post an areawide bond of $3,000,000,the MMS has allowed the Company to fulfill such bonding requirements through an insurance policy. During the third quarter of 1999, ERT substantially completed its 1999 Well Exploitation Program, which included five recompletions and which led to the sale of its interest in certain offshore blocks. It is an operating policy that ERT will sell assets (offshore leases, platforms, compressors, etc.) when the expected future revenue stream can be accelerated in a single transaction. Accordingly, proceeds received from such transactions are recorded as revenue in the period received. These sales were structured as Section 1031 "Like Kind" exchanges for tax purposes. Accordingly, the cash received was restricted to use for subsequent acquisitions of additional natural gas and oil properties. Since inception ERT has acquired interests in 41 offshore leases, sold seven (two in 1997 and two in 1998), and taken one field full cycle to decommissioning. The well exploitation work completed during the third quarter also enabled ERT to assess and write down the carrying value of three ERT fields, including one where a third party vendor damaged the reservoir formation. The net result of the sales and the 1999 Well Exploitation Program was to add approximately thirteen cents to 1999 diluted earnings per share. 36 39 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. ACCRUED LIABILITIES: Accrued liabilities consisted of the following (in thousands):
1999 1998 ------- ------- Accrued payroll and related benefits........................ $ 6,606 $ 5,198 Workers' compensation claims................................ 497 1,919 Workers' compensation claims to be reimbursed............... 6,241 867 Other....................................................... 3,879 2,036 ------- ------- Total accrued liabilities......................... $17,223 $10,020 ======= =======
6. REVOLVING CREDIT FACILITY: Since April 1997, the Company has had a revolving credit facility of $40 million available. Interest rates vary from .5% above prime and 2% above the Eurodollar base rate to prime and 1.25 to 2.50 percent above Eurodollar based on specific provisions set forth in the loan agreement. Covenant restrictions include only a fixed charge ratio. The Company was in compliance with these debt covenants at December 31, 1999. 7. FEDERAL INCOME TAXES: Federal income taxes have been provided based on the statutory rate of 35 percent in 1999 and 35 percent in 1997 and 1998 adjusted for items which are allowed as deductions for federal income tax reporting purposes, but not for book purposes. The primary differences between the statutory rate and the Company's effective rate are as follows:
1999 1998 1997 ---- ---- ---- Statutory rate.............................................. 35% 35% 35% Research and development tax credits........................ (3) (1) -- Other....................................................... 1 1 -- -- -- -- Effective rate.................................... 33% 35% 35% == == ==
Components of the provision for income taxes reflected in the statements of operations consist of the following (in thousands):
1999 1998 1997 ------ ------- ------ Current................................................... $4,167 $ 8,550 $4,010 Deferred.................................................. 4,298 4,469 3,789 ------ ------- ------ $8,465 $13,019 $7,799 ====== ======= ======
Deferred income taxes result from those transactions which affect financial and taxable income in different years. The nature of these transactions and the income tax effect of each as of December 31, 1999 and 1998, is as follows (in thousands):
1999 1998 ------- ------- Deferred tax liabilities -- Depreciation.............................................. $16,837 $13,539 Deferred tax assets -- Reserves, accrued liabilities and other................... (532) (416) ------- ------- Net deferred tax liability........................ $16,305 $13,123 ======= =======
37 40 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 8. COMMITMENTS AND CONTINGENCIES: Lease Commitments During 1999, CDI acquired Hvide Marine's interest in Cal Dive Aker CAHT I, LLC (CAHT I), the company which owned the Cal Dive Aker Dove (a newbuild DP anchor handling and subsea construction vessel which commenced operations in September 1999) for a total of $18.9 million. CDI effectively owns 56% of CAHT I and accordingly results of operations of this company are consolidated in the accompanying financial statements with Aker's share being reflected as minority interest. In December, 1999, CAHT I entered into a sale-leaseback of the Cal Dive Aker Dove. Cal Dive's portion of the proceeds received totaled $20 million and resulted in a gain of $1.4 million which was deferred and is being amortized over the ten year term of the lease. The lease, which is accounted for as an operating lease, requires CAHTI to make quarterly payments of $988,000 and contains a renewal option and options to purchase the vessel for amounts approximating fair market value after 8 1/2 years of the lease term and at the end of the lease term. The Company occupies several facilities under noncancelable operating leases, with the more significant leases expiring in the years 2004 and 2007. Future minimum rentals under these leases are $3.4 million at December 31, 1999 with $579,000 due in 2000, $599,000 in 2001, $622,000 in 2002, $676,000 in 2003, $516,000 in 2004 and the balance thereafter. Total rental expense under these operating leases was $673,000, $601,000 and $376,000 for the years ended December 31, 1999, 1998 and 1997, respectively. Insurance and Litigation The Company carries hull protection on vessels, indemnity insurance and a general umbrella policy. All onshore employees are covered by workers' compensation, and all offshore employees, including divers and tenders, are covered by Jones Act employee coverage, the maritime equivalent of workers' compensation. The Company is exposed to deductible limits on its insurance policies, which vary from $5,000 to a maximum of $100,000 per accident occurrence. Effective August 1, 1992, the Company adopted a self-insured (within specified limits) medical and health benefits program for its employees whereby the Company is exposed to a maximum of $15,000 per claim. In 1998, CDI entered into a subcontract with Seacore Marine Contractors Limited (Seacore) to provide a vessel (the Sea Sorceress) for the excavation of glory holes on the Terra Nova Project in the North Atlantic ocean. Seacore was in turn contracted by Coflexip Stena Offshore. Due to unforeseen difficulties with respect to the sea states and soil conditions, Coflexip chose to suspend glory hole dredging for the 1998 season. Subsequently, Coflexip formally terminated the contract with Seacore and issued a call against a performance bond provided by Seacore. CDI has provided Seacore a performance bond of $5 million with respect to the subcontract of the Sea Sorceress although no call has been made on this bond. Seacore and CDI believe the contract was wrongfully terminated and are vigorously defending this claim in arbitration. The Company incurs workers' compensation claims in the normal course of business, which management believes are covered by insurance. The Company, its insurers and legal counsel analyze each claim for potential exposure and estimate the ultimate liability of each claim. Amounts accrued and receivable from insurance companies, above the applicable deductible limits, are reflected in other current assets in the consolidated balance sheet. Such amounts were $6,241,000 and $867,000 as of December 31, 1999 and 1998, respectively. See related accrued liabilities at Note 5. The Company has not incurred any significant losses as a result of claims denied by its insurance carriers. In addition, the Company from time to time incurs other claims, such as contract disputes, in the normal course of business. In the opinion of management, the ultimate liability to the Company, if any, which may result from the claims discussed above will not materially affect the Company's consolidated financial position, results of operations or net cash flows. 38 41 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 9. EMPLOYEE BENEFIT PLANS: Defined Contribution Plan The Company sponsors a defined contribution 401(k) retirement plan covering substantially all of its employees. The Company's contributions and cost are determined annually as 50 percent of each employee's contribution up to 5 percent of the employee's salary. The Company's costs related to this plan totaled $375,000, $431,000 and $305,000 for the years ended December 31, 1999, 1998 and 1997, respectively. Stock-Based Compensation Plans During 1995, the Board of Directors and shareholders approved the 1995 Long-Term Incentive Plan (the Incentive Plan). Under the Incentive Plan, a maximum of 10% of the total shares of Common Stock issued and outstanding may be granted to key executives and selected employees who are likely to make a significant positive impact on the reported net income of the Company. The Incentive Plan is administered by a committee which determines, subject to approval of the Compensation Committee of the Board of Directors, the type of award to be made to each participant and sets forth in the related award agreement the terms, conditions and limitations applicable to each award. The committee may grant stock options, stock appreciation rights, or stock and cash awards. Options granted to employees under the Incentive Plan vest 20% per year for a five year period, have a maximum exercise life of five years and, subject to certain exceptions, are not transferable. Effective May 12, 1998, the Company adopted a qualified, non-compensatory Employee Stock Purchase Plan ("ESPP"), which allows employees to acquire shares of common stock through payroll deductions over a six month period. The purchase price is equal to 85 percent of the fair market value of the common stock on either the first or last day of the subscription period, whichever is lower. Purchases under the plan are limited to 10 percent of an employee's base salary. Under this plan 11,238 and 13,937 shares of common stock were purchased in the open market at a weighted average share price of $24.38 and $21.25 during 1999 and 1998, respectively. The Incentive Plan and ESPP are accounted for using APB Opinion No. 25, and therefore no compensation expense is recorded. If SFAS Statement No. 123 had been used for the accounting of these plans, the Company's pro forma net income for 1999, 1998 and 1997 would have been $16,218,000, $23,735,000 and $14,023,000 respectively, and the Company's pro forma diluted earnings per share would have been $1.06, $1.59 and $1.07 respectively. These pro forma results exclude consideration of options granted prior to January 1, 1995, and therefore may not be representative of that to be expected in future years. All of the options outstanding at December 31, 1999, have exercise prices as follows: 184,500 shares at $4.50, 116,054 at $7.90, 387,000 shares at $9.50, 82,000 shares at $13.00, 84,770 shares at $20.56 and 124,280 shares ranging from $14.00 to $32.00 and a weighted average remaining contractual life of 2.49 years. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used: expected dividend yields of 0 percent; expected lives of five years risk-free interest rate assumed to be 5.5 percent in 1997, 5.0 percent in 1998 and 5.5 percent in 1999 and expected volatility to be 36 percent in 1997 and 59 percent in 1998 and 1999. The fair value of shares issued under the ESPP was based on the 15% discount received by the employees. 39 42 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Options outstanding are as follows:
1999 1998 1997 -------------------- -------------------- ------------------ WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE --------- -------- --------- -------- ------- -------- Options outstanding, beginning of year....... 1,044,600 $ 9.40 994,500 $8.66 544,500 $4.50 Granted................... 238,969 12.07 325,850 23.55 540,000 12.17 Exercised................. (292,965) 6.84 (56,750) 5.03 (22,000) 4.50 Terminated................ ( 12,000) 4.50 (219,000) 28.24 (68,000) 4.50 --------- ------ --------- ----- ------- ----- Options outstanding, December 31............. 978,604 $11.18 1,044,600 $9.40 994,500 $8.66 Options exercisable, December 31............. 247,744 $ 8.59 222,950 $6.50 199,604 $4.50 ========= ====== ========= ===== ======= =====
Options granted in 1999 include 143,639 shares issued in connection with the August 1, 1999 acquisition of Aquatica, Inc., which provided for conversion of Aquatica employee stock options into Cal Dive stock options at the same ratio which Aquatica common shares were converted into Cal Dive common shares. Options granted and options terminated under the Incentive Plan for 1998 include options which were repriced on November 6, 1998. The options which were repriced were originally granted between August 25, 1997 and May 11, 1998 with original exercise prices between $28.38 and $37.25. Options for 165,000 shares were cancelled on November 6, 1998 and a proportionately reduced number of shares (100,850) were reissued at an exercise price of $20.56 per share with a new five year vesting period. 10. COMMON STOCK: The Company's amended and restated Articles of Incorporation provide for authorized Common Stock of 60,000,000 shares with no par value per share. On April 11, 1997, Coflexip purchased approximately 3,700,000 shares of the Company's stock, consisting of approximately 2.1 million shares sold by management of the Company and 1.1 million shares sold by First Reserve Funds at a price of $9.46 per share. Coflexip agreed to accept approximately 500,000 shares of the Company's Common Stock as payment for two ROVs at published retail prices as part of this transaction. The Company also entered into a joint venture with Coflexip (Quantum Offshore Contractors, L.L.C.) designed to target larger EPIC contracts in the Gulf of Mexico. Such contracts did not develop and accordingly in December 1999 this venture was dissolved in favor of a new business arrangement which will enable the parties to consult and cooperate with one another as they see fit on a project-by-project basis. In conjunction with the Coflexip transaction, the Company entered into a new Shareholders Agreement. The new Shareholders Agreement provides that, except in limited circumstances (including issuance of securities under stock option plans or in conjunction with acquisitions), the Company shall provide preemptive rights to acquire the Company's securities to each of Coflexip and the Executive Directors. The Shareholders Agreement also provides that the Company will not enter into an agreement (i) to sell the Company, (ii) to retain an advisor to sell the Company or (iii) to pursue any acquisition in excess of 50% of the Company's market capitalization without first notifying Coflexip in writing and providing Coflexip the opportunity to consummate an acquisition on terms substantially equivalent to any proposal. The Company completed an initial public offering of common stock on July 7, 1997, with the sale of 4.1 million shares at $15 per share. Of the 4.1 million shares, 2,875,000 shares were sold by the Company and 40 43 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 1,265,000 shares were sold by First Reserve Funds. Net proceeds to the Company of approximately $39.4 million were used to retire all of its then outstanding long-term indebtedness of $20 million. In May 1998, the Company completed a secondary offering of 2,867,070 shares of common stock at $33.50 per share on behalf of certain selling shareholders. The Company received no proceeds from the offering. 11. BUSINESS SEGMENT INFORMATION (IN THOUSANDS): The following summarizes certain financial data by business segment:
YEAR ENDED DECEMBER 31, ------------------------------ 1999 1998 1997 -------- -------- -------- Revenues -- Subsea and salvage................................. $128,435 $139,310 $ 92,860 Natural gas and oil production..................... 32,519 12,577 16,526 -------- -------- -------- Total...................................... $160,954 $151,887 $109,386 ======== ======== ======== Income from operations -- Subsea and salvage................................. $ 15,817 $ 31,440 $ 16,411 Natural gas and oil production..................... 8,207 1,968 6,078 -------- -------- -------- Total...................................... $ 24,024 $ 33,408 $ 22,489 ======== ======== ======== Net interest (income) expense and other -- Subsea and salvage................................. $ (264) $ (705) $ 379 Natural gas and oil production..................... (585) (398) (171) -------- -------- -------- Total...................................... $ (849) $ (1,103) $ 208 ======== ======== ======== Provision for income taxes -- Subsea and salvage................................. $ 5,431 $ 12,195 $ 5,614 Natural gas and oil production..................... 3,034 824 2,185 -------- -------- -------- Total...................................... $ 8,465 $ 13,019 $ 7,799 ======== ======== ======== Identifiable assets -- Subsea and salvage................................. $197,570 $142,629 $107,420 Natural gas and oil production..................... 46,152 21,606 18,180 -------- -------- -------- Total...................................... $243,722 $164,235 $125,600 ======== ======== ======== Capital expenditures -- Subsea and salvage................................. $ 60,662 $ 10,923 $ 26,984 Natural gas and oil production..................... 16,785 3,963 1,952 -------- -------- -------- Total...................................... $ 77,447 $ 14,886 $ 28,936 ======== ======== ======== Depreciation and amortization -- Subsea and salvage................................. $ 9,459 $ 6,966 $ 4,000 Natural gas and oil production..................... 11,156 2,597 3,512 -------- -------- -------- Total...................................... $ 20,615 $ 9,563 $ 7,512 ======== ======== ========
41 44 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 12. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED): The following information regarding the Company's oil and gas producing activities is presented pursuant to SFAS No. 69, "Disclosures About Oil and Gas Producing Activities" (in thousands). Capitalized Costs Aggregate amounts of capitalized costs relating to the Company's oil and gas producing activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated are presented below. The Company has no capitalized costs related to unproved properties.
AS OF DECEMBER 31, ------------------ 1999 1998 -------- ------- Proved properties being amortized........................... $ 49,037 $22,530 Less -- Accumulated depletion, depreciation and amortization.............................................. (19,530) (9,082) -------- ------- Net capitalized costs............................. $ 29,507 $13,448 ======== =======
Included in capitalized costs is the Company's estimate of its proportionate share of decommissioning liabilities assumed relating to these properties. As of December 31, 1999 and 1998, such liabilities totaled $27.0 million and $9.9 million, respectively, and are also reflected as decommissioning liabilities in the accompanying consolidated balance sheet. Costs Incurred in Oil and Gas Producing Activities The following table reflects the costs incurred in oil and gas property acquisition and development activities during the dates indicated:
YEAR ENDED DECEMBER 31, ------------------------- 1999 1998 1997 ------- ------ ------ Proved property acquisition costs......................... $22,610 $5,416 $2,687 Development costs......................................... 5,002 2,281 385 ------- ------ ------ Total costs incurred............................ $27,612 $7,697 $3,072 ======= ====== ======
Results of Operations For Oil and Gas Producing Activities
YEAR ENDED DECEMBER 31, --------------------------- 1999 1998 1997 ------- ------- ------- Revenues................................................ $32,519 $12,577 $16,526 Production (lifting) costs.............................. 9,433 6,820 4,651 Depreciation, depletion and amortization................ 11,156 2,597 3,512 ------- ------- ------- Pretax income from producing activities................. 11,930 3,160 8,363 Income tax expenses..................................... 3,034 1,106 2,927 ------- ------- ------- Results of oil and gas producing activities............. $ 8,896 $ 2,054 $ 5,436 ======= ======= =======
Estimated Quantities of Proved Oil and Gas Reserves Proved oil and gas reserve quantities are based on estimates prepared by Company engineers in accordance with guidelines established by the Securities and Exchange Commission. The Company's estimates of reserves at December 31, 1999, have been reviewed by Miller and Lents, Ltd., independent petroleum engineers. All of the Company's reserves are located in the United States. Proved reserves cannot 42 45 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) be measured exactly because the estimation of reserves involves numerous judgmental determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history, new geological and geophysical data and changes in economic conditions. As of December 31, 1997, 4,500 Bbls. of oil and 6,325,700 Mcf. of gas of the Company's proved reserves were undeveloped. As of December 31, 1998, 400 Bbls. of oil and 1,153,300 Mcf. of gas were undeveloped. As of December 31, 1999, 337,500 Bbls. of oil and 284,800 Mcf. of gas were undeveloped.
OIL GAS RESERVE QUANTITY INFORMATION (MBBLS.) (MMCF.) - ---------------------------- -------- ------- Total proved reserves at December 31, 1996.................. 124 24,596 Revisions of previous estimates........................... (21) 1,831 Production................................................ (51) (5,385) Purchases of reserves in place............................ 149 2,115 Sales of reserves in place................................ (1) (912) ----- ------ Total proved reserves at December 31, 1997.................. 200 22,245 Revisions of previous estimates........................... (123) (1,706) Production................................................ (67) (4,535) Purchase of reserves in place............................. 60 6,631 Sales of reserves in place................................ -- (201) ----- ------ Total proved reserves at December 31, 1998.................. 70 22,434 Revisions of previous estimates........................... 1,091 (2,392) Production................................................ (339) (6,819) Purchase of reserves in place............................. 888 17,218 Sales of reserves in place................................ (8) (5,060) ----- ------ Total proved reserves at December 31, 1999.................. 1,702 25,381 ===== ======
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:
1999 1998 1997 -------- -------- -------- Future cash inflows.................................. $101,686 $ 47,691 $ 59,819 Future costs -- Production...................................... (30,550) (17,412) (23,675) Development and abandonment..................... (30,303) (11,232) (6,917) -------- -------- -------- Future net cash flows before income taxes............ 40,833 19,047 29,227 Future income taxes................................ (16,191) (6,477) (7,927) -------- -------- -------- Future net cash flows................................ 24,642 12,570 21,300 Discount at 10% annual rate........................ (1,799) (2,414) (1,540) -------- -------- -------- Standardized measure of discounted future net cash flows.............................................. $ 22,843 $ 10,156 $ 19,760 ======== ======== ========
43 46 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Changes in Standardized Measure of Discounted Future Net Cash Flows Principal changes in the standardized measure of discounted future net cash flows attributable to the Company's proved oil and gas reserves are as follows:
1999 1998 1997 -------- ------- -------- Standardized measure, beginning of year............... $ 10,156 $19,760 $ 33,805 Sales, net of production costs........................ (23,086) (5,757) (11,441) Net change in prices, net of production costs......... 15,968 (4,573) (17,707) Changes in future development costs................... (1,227) (1,736) 160 Development costs incurred............................ 5,002 2,281 385 Accretion of discount................................. 1,537 2,711 4,870 Net change in income taxes............................ (9,776) 2,120 7,544 Purchases of reserves in place........................ 31,309 4,403 3,282 Sales of reserves in place............................ (14,456) (57) (2,480) Net change due to revision in quantity estimates...... (7,591) (3,192) 2,289 Changes in production rates (timing) and other........ (175) (5,804) (947) -------- ------- -------- Standardized measure, end of year..................... $ 22,843 $10,156 $ 19,760 ======== ======= ========
13. REVENUE ALLOWANCE ON GROSS AMOUNTS BILLED: The following table sets forth the activity in the Company's Revenue Allowance on Gross Amounts Billed for each of the three years in the period ended December 31, 1999 (in thousands):
1999 1998 1997 ------- ------- ------- Beginning balance....................................... $ 1,335 $ 1,822 $ 1,021 Additions............................................... 1,923 2,998 3,058 Deductions.............................................. (1,469) (3,485) (2,257) ------- ------- ------- Ending balance.......................................... $ 1,789 $ 1,335 $ 1,822 ======= ======= =======
See Note 2 for a detailed discussion regarding the Company's accounting policy on the Revenue Allowance on Gross Amounts Billed. 44 47 CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED): The offshore marine construction industry in the Gulf of Mexico is highly seasonal as a result of weather conditions and the timing of capital expenditures by the oil and gas companies. Historically, a substantial portion of the Company's services has been performed during the summer and fall months. As a result, historically a disproportionate portion of the Company's revenues and net income is earned during such period. The following is a summary of consolidated quarterly financial information for 1999 and 1998.
QUARTER ENDED ----------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- ------- ------------ ----------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Fiscal 1999 Revenues................................. $26,006 $34,104 $58,470 $42,374 Gross profit............................. 5,257 5,724 17,955 8,315 Net income............................... 2,087 2,641 9,017 3,154 Net income per share: Basic.................................. .14 .18 .59 .20 Diluted................................ .14 .18 .58 .20 Fiscal 1998 Revenues................................. $33,157 $38,526 $42,913 $37,291 Gross profit............................. 10,563 12,134 15,116 11,395 Net income............................... 5,243 5,954 7,577 5,351 Net income per share: Basic.................................. 0.36 0.41 0.52 0.37 Diluted................................ 0.35 0.40 0.51 0.36
15. SUBSEQUENT EVENTS (UNAUDITED): Acquisition of Offshore Blocks During the first quarter of 2000 ERT acquired interests in six offshore blocks from EEX Corporation and agreed to operate the remaining EEX properties on the Outer Continental Shelf (OCS). The acquired offshore blocks include working interests from 40% to 75% in five platforms, one caisson and 13 wells currently producing 23 mmcf per day (13 mmcf net). ERT exchanged cash of $4.9 million and assumed EEX's prorated share of the abandonment obligation for the acquired interests, and entered into a two-year contract to manage the remaining EEX operated properties. EEX personnel who operated these properties also became ERT employees. 45 48 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Act of 1934 in connection with the Company's 2000 Annual Meeting of Shareholders. See also "Executive Officers of the Registrant" appearing in Part I of this Report. ITEM 11. EXECUTIVE COMPENSATION. The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Act of 1934 in connection with the Company's 2000 Annual Meeting of Shareholders. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Act of 1934 in connection with the Company's 2000 Annual Meeting of Shareholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Act of 1934 in connection with the Company's 2000 Annual Meeting of Shareholders. 46 49 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. 1. Financial Statements The following financial statements included on pages 28 through 45 in this Annual Report are for the fiscal year ended December 31, 1999. Independent Auditors' Report. Consolidated Balance Sheets as of December 31, 1999 and 1998. Consolidated Statements of Operations for the Years Ended December 31, 1999, 1998 and 1997. Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 1999, 1998 and 1997. Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997. Notes to Consolidated Financial Statements. Financial Statement Schedules All financial statement schedules are omitted because the information is not required or because the information required is in the financial statements or notes thereto. (2) Report on Form 8-K. None. (3) Exhibits. Pursuant to Item 601(b)(4)(iii), the Registrant agrees to forward to the commission, upon request, a copy of any instrument with respect to long-term debt not exceeding 10% of the total assets of the Registrant and its consolidated subsidiaries. The following exhibits are filed as part of this Annual Report:
EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 -- Amended and Restated Articles of Incorporation of Registrant, incorporated by reference to Exhibit 3.1 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 3.2 -- Bylaws of Registrant, incorporated by reference to Exhibit 3.2 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 4.1 -- Amended and Restated Loan and Security Agreement by and among the Company, ERT and Fleet Capital Corporation (f/n/a Shawmut Capital Corporation) dated as of May 23, 1995, incorporated by reference to Exhibit 4.1 to the Form S-1 Registration Statement filed by the Registrant on May 1, 1997 (Reg. No. 333-26357). 4.2 -- Amendment No. 5 to Loan, incorporated by reference to Exhibit 4.2 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333- 26357). 4.3 -- Form of Common Stock certificate, incorporated by reference to Exhibit 4.1 to the Form S-1 filed by the Company on May 1, 1997 (Reg. No. 333-26357).
47 50
EXHIBIT NUMBER DESCRIPTION ------- ----------- 4.4 -- Shareholders Agreement by and among the Company, First Reserve Secured Energy Asset Fund, First Reserve Fund V, First Asset Fund, First Reserve Fund V, First Reserve Fund V-2, First Reserve Fund (collectively the "Selling Shareholders"), Messrs. Kratz, Nelson and other shareholders of the Company incorporated by reference to Exhibit 4.4 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 4.5 -- Registration Rights Agreement by and between the Company, the Selling Shareholders, Messrs. Kratz, Nelson and other shareholders of the Company incorporated by reference to Exhibit 4.5 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 4.6 -- Registration Rights Agreement by and between the Company and Coflexip incorporated by reference to Exhibit 4.6 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 10.1 -- Purchase Agreement dated April 11, 1997 by and between Coflexip and the Company incorporated by reference to Exhibit 10.1 to the Form S-1 Registration Statement filed by Company on May 1, 1997 (Reg. No. 333-26357). 10.3 -- 1995 Long Term Incentive Plan, as amended incorporated by reference to Exhibit 10.3 to the Form S-1 Registration Statement filed by Company on May 1, 1997 (Reg. No. 333-26357). *10.2 -- 1999 Annual Incentive Compensation Program. 10.5 -- Employment Agreement between Owen Kratz and the Company dated February 28, 1999. 10.6 -- Employment Agreement between Martin R. Ferron and the Company dated February 28, 1999. 10.7 -- Employment Agreement between S. James Nelson and the Company dated February 28, 1999. 10.8 -- Employment Agreement between Louis L. Tapscott and the Company dated February 28, 1999. 21.1 -- Subsidiaries of the Registrant. The Company has four subsidiaries, Energy Resource Technologies, Inc., Cal Dive Offshore, Ltd., Aquatica, Inc. and *23.1 -- Consent of Arthur Andersen LLP. *27.1 -- Financial Data Schedule.
- --------------- Management contract or compensation plan. * Filed herewith. 48 51 SIGNATURES Pursuant to the requirements option 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned. thereunto duly authorized. CAL DIVE INTERNATIONAL, INC. By: /s/ S. JAMES NELSON ---------------------------------- S. James Nelson Executive Vice President, Chief Financial Officer March 29, 1999 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ---- /s/ OWEN KRATZ Chairman, Chief Executive Officer April 7, 2000 - ----------------------------------------------------- and Director Owen Kratz /s/ MARTIN R. FERRON President, Chief Operating April 7, 2000 - ----------------------------------------------------- Officer and Director Martin R. Ferron /s/ S. JAMES NELSON Executive Vice President, Chief April 7, 2000 - ----------------------------------------------------- Financial Officer and Director S. James Nelson /s/ A. WADE PURSELL Vice President -- Finance, Chief April 7, 2000 - ----------------------------------------------------- Accounting Officer A. Wade Pursell /s/ GORDON F. AHALT Director April 7, 2000 - ----------------------------------------------------- Gordon F. Ahalt /s/ BERNARD J. DUROC-DANNER Director April 7, 2000 - ----------------------------------------------------- Bernard J. Duroc-Danner /s/ CLAIRE GIRAUT Director April 7, 2000 - ----------------------------------------------------- Claire Giraut /s/ ALINE MONTEL Director April 7, 2000 - ----------------------------------------------------- Aline Montel /s/ KEVIN WOOD Director April 7, 2000 - ----------------------------------------------------- Kevin Wood
49 52 EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 -- Amended and Restated Articles of Incorporation of Registrant, incorporated by reference to Exhibit 3.1 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 3.2 -- Bylaws of Registrant, incorporated by reference to Exhibit 3.2 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 4.1 -- Amended and Restated Loan and Security Agreement by and among the Company, ERT and Fleet Capital Corporation (f/n/a Shawmut Capital Corporation) dated as of May 23, 1995, incorporated by reference to Exhibit 4.1 to the Form S-1 Registration Statement filed by the Registrant on May 1, 1997 (Reg. No. 333-26357). 4.2 -- Amendment No. 5 to Loan, incorporated by reference to Exhibit 4.2 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333- 26357). 4.3 -- Form of Common Stock certificate, incorporated by reference to Exhibit 4.1 to the Form S-1 filed by the Company on May 1, 1997 (Reg. No. 333-26357). 4.4 -- Shareholders Agreement by and among the Company, First Reserve Secured Energy Asset Fund, First Reserve Fund V, First Asset Fund, First Reserve Fund V, First Reserve Fund V-2, First Reserve Fund (collectively the "Selling Shareholders"), Messrs. Kratz, Nelson and other shareholders of the Company incorporated by reference to Exhibit 4.4 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 4.5 -- Registration Rights Agreement by and between the Company, the Selling Shareholders, Messrs. Kratz, Nelson and other shareholders of the Company incorporated by reference to Exhibit 4.5 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 4.6 -- Registration Rights Agreement by and between the Company and Coflexip incorporated by reference to Exhibit 4.6 to the Form S-1 Registration Statement filed by the Company on May 1, 1997 (Reg. No. 333-26357). 10.1 -- Purchase Agreement dated April 11, 1997 by and between Coflexip and the Company incorporated by reference to Exhibit 10.1 to the Form S-1 Registration Statement filed by Company on May 1, 1997 (Reg. No. 333-26357). *10.2 -- 1999 Annual Incentive Compensation Program. 10.3 -- 1995 Long Term Incentive Plan, as amended incorporated by reference to Exhibit 10.3 to the Form S-1 Registration Statement filed by Company on May 1, 1997 (Reg. No. 333-26357). 10.5 -- Employment Agreement between Owen Kratz and the Company dated February 28, 1999. 10.6 -- Employment Agreement between Martin R. Ferron and the Company dated February 28, 1999. 10.7 -- Employment Agreement between S. James Nelson and the Company dated February 28, 1999. 10.8 -- Employment Agreement between Louis L. Tapscott and the Company dated February 28, 1999.
53
EXHIBIT NUMBER DESCRIPTION ------- ----------- 21.1 -- Subsidiaries of the Registrant. The Company has four subsidiaries, Energy Resource Technologies, Inc., Cal Dive Offshore, Ltd., Aquatica, Inc. and *23.1 -- Consent of Arthur Andersen LLP. *27.1 -- Financial Data Schedule.
- --------------- * Filed herewith. EX-10.2 2 1999 ANNUAL INCENTIVE COMPENSATION PROGRAM 1 EXHIBIT 10.2 1999 ANNUAL INCENTIVE COMPENSATION PROGRAM ================================================================================ COMPENSATION PHILOSOPHY CDI Incentive Compensation Plans are designed to align the interests of employees with those of Cal Dive shareholders to the maximum extent possible. Employees will share in the superior performance of the company recognizing that the shareholders are entitled to a threshold level of performance in exchange for base salaries. The threshold level is based on the Annual Budget established by management and approved by the Board of Directors. Incentives based upon performance above that threshold level can result in total cash compensation to CDI employees well above competitive levels for the industry. The 1999 Incentive Compensation Program is a direct continuation of the program established in 1993. It is designed to reward key team members for the contribution made towards achieving the company's growth and profitability targets. Potential bonuses under this program are limited only by the success and cost effectiveness of our combined effort. General terms of the 1999 Plan (which is based upon the 1998 Incentive Compensation Plan which was established after review by the Human Capital Services Division of Arthur Andersen LLP) include: * THRESHOLD PERFORMANCE: Incentive compensation is earned when financial performance exceeds 100% of the 1999 Business Plan (up from 80% last year). * PARTICIPATION: Continued expanded participation in the Operations pool (i.e., Project Management et al) to reflect, among other things, the significance of the Morgan City Operations Base. * BONUS POOL: The bonus pool of the Operations Group will change to 50% of the first $4 million over the incentive target and thereafter revert to the 25%. The Administrative pool adds 25% of the first $2 million over the incentive target and thereafter reverts to 6% (as last year). * SG&A: Operations pool is increased or decreased by variances to budgeted SG&A expenses (as defined); i.e., Sales Department and administrative costs related to personnel in the Operations pool (same as last year). * DISCRETIONARY COMPONENT: 30% of the allocated incentive award is based upon discretion of Senior management and achievement of individual goals (same as last year). * SUPPORT STAFF: Each Group may use a portion of their bonus pool or incentives not awarded in the discretionary component to make bonus payments to support staff. Page 1 2 GENERAL CONDITIONS TO ALL PLANS ================================================================================ ELIGIBILITY FOR PARTICIPATION Participants must be on the payroll no later than June 30, 1999. Participants who are not on the payroll as of January 1, 1999, will have their OPPORTUNITY pro-rated by their months of service. Incentive compensation awards will be granted to those participants who have met the performance criteria set forth in this policy and who are on the payroll December 31, 1999, for incentive compensation authorized under this plan. This plan is not to be construed in any way as a guarantee of employment or an employment contract. METHOD OF PAYMENT Earned incentive compensation will be paid in cash by March 15. CLARIFICATION/INTERPRETATION/MODIFICATION OF THE PLAN The Compensation Committee of the Cal Dive Board of Directors shall have the right and the sole authority at any time and without restriction to clarify, interpret and/or modify this plan. Page 2 3 PROJECT MANAGEMENT GROUP SPECIAL PROJECTS GROUP ACCOUNT MANAGER GROUP MORGAN CITY OPERATIONS GROUP ================================================================================ This program is for the benefit of certain personnel in the Groups listed above, the Vice Presidents of these Groups, and such other participants as determined by the Group Vice Presidents and Executive Management. Each eligible participant's incentive compensation OPPORTUNITY will be based on the following: 1. No incentive will be paid until attaining 1999 budgeted "Subsea Division" (exclusive of ERT) gross profit of $29,179,000. 2. Variances to budgeted Subsea SG&A (as defined) will be added to (or deducted from) gross profit in determining 1 above. 3. A bonus pool will be established equal to (a) 50% of the first four million dollars of gross profit (as adjusted) in excess of the goal, plus (b) 25% of any Subsea Division gross profits in excess of $33,179,000 subject to a cap of $3.0 million. The bonus pool will be divided into three tiers and will be available as an incentive compensation OPPORTUNITY for each eligible participant in direct proportion to the ratio of the eligible participant base salaries. Each participant's OPPORTUNITY will be awarded based as follows: 1. 70% of the total opportunity will be awarded based on achieving the financial goals. 2. From 0 to 30% of the total opportunity will be awarded based on a subjective evaluation by Executive Management regarding the individual's efforts, contribution and success in achieving specific goals established by the group Vice President and Martin Ferron. Any portion of the opportunity that is not awarded may be reallocated to other plan participants. 3. Discretionary bonuses may be paid to support staff from the bonus pool or incentives not awarded in the discretionary component. The gross profit goal reflects management's assessment of revenue producing assets on hand or expected to be acquired at the time the Business Plan is prepared. The goal shall NOT be adjusted should any of these assets be sold or not acquired subsequent to the Business Plan being approved by the Board of Directors. However, if the company subsequently purchases or otherwise acquires new assets with the expectation of increasing the gross profit of the Subsea division, the gross profit levels will be adjusted to allow for a reasonable return to the company. This adjustment will be based on the economics presented to the Board of Directors as justification for the new equipment or service (the approved AFE) and will be prorated for months in service. In addition, gross profit is NOT to be adjusted for changes in accounting policy made during a fiscal year. Page 3 4 EXECUTIVE MANAGEMENT ACCOUNTING & ADMINISTRATIVE PERSONNEL ================================================================================ This program is for the benefit of certain members of executive management and corporate accounting and administrative personnel. Each eligible participant's incentive compensation opportunity will be based upon the following: 1. Attaining the consolidated net income of $19,500,000 as budgeted in the 1999 Business Plan. 2. Upon attaining the net income goal, a bonus pool equal to 75% of all eligible persons assigned bonus percentages will be created 3. In addition, a bonus pool will be established based upon (a) 25% of the first $2 million of net income in excess of targeted net income, plus (b) 6% of any consolidated net income in excess of targeted net income plus $2 million. The bonus pool will be available for each eligible participant in direct proportion to the ratio of eligible participant base salaries. Each participants opportunity will be awarded based as follows: 1. 70% of the total opportunity will be awarded based upon achieving financial goals. 2. From 0 to 30% of the total opportunity will be awarded based upon a subjective evaluation by the Compensation Committee and Executive Management regarding the individual's efforts, contribution and success in achieving specific goals established by the Group Vice President and Board of Directors. Any portion of the opportunity that is not awarded may not be reallocated to other participants. 3. Discretionary bonuses may be paid to support staff from the bonus pool or incentives not awarded in the discretionary component. If the company purchases or otherwise acquires new assets with the expectation of increasing the net income of Subsea Division, consolidated net income will be adjusted to allow for a reasonable return to the company. This adjustment will be based on the economics presented to the Board of Directors for justification for the new equipment or service (the approved AFE) and will be prorated for months in service. Page 4 EX-23.1 3 CONSENT OF ARTHUR ANDERSEN LLP 1 EXHIBIT 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 17, 2000, included in this Form 10-K into the Company's previously filed Registration Statements File No. 333-50289 and No. 333-58817. /s/ ARTHUR ANDERSEN LLP Houston, Texas March 30, 2000 EX-27.1 4 FINANCIAL DATA SCHEDULE
5 1,000 YEAR DEC-31-1999 JAN-01-1999 DEC-31-1999 19,996 0 53,410 1,789 0 87,944 180,519 45,862 243,722 49,057 0 0 0 73,311 77,561 243,722 160,954 160,954 123,703 136,930 (491) 0 (849) 25,473 8,465 16,899 0 0 0 16,899 1.13 1.10
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