ITEM 1. BUSINESS.
OVERVIEW
We are a leading energy services company involved in projects from the shallowest to the deepest waters of the Gulf of Mexico. We have a reputation for innovation in our subsea construction techniques, equipment design and methods of partnering with customers. Our diversified fleet of 23 vessels and 19 remotely operated vehicles (ROVs) performs services that support drilling, well completion, construction and decommissioning projects involving pipelines, production platforms, risers and subsea production systems. We also acquire interests in natural gas and oil properties and related production facilities as part of our Production Partnering business. Our customers include major and independent natural gas and oil producers, pipeline transmission companies and offshore engineering and construction firms.
We have positioned for work in water depths greater than 1,000 feet (the "Deepwater") by assembling a technically advanced fleet of dynamically positioned (DP) vessels and ROVs and a highly experienced group of support professionals. Our DP vessels serve as work platforms for subsea solutions provided by us working with our alliance partners, a team of internationally recognized contractors and manufacturers. Our new ROV subsidiary, Canyon Offshore, Inc., offers survey, engineering, repair, maintenance and international cable burial services. We are also a leader in solving the challenges encountered in Deepwater construction, with many of our projects using methods we have developed. Most notably, our newest and most advanced Deepwater semi-submersible multi-service vessel ("MSV"), the Q4000, incorporates our latest patented technologies. We anticipate that the Q4000 will improve Deepwater completion and construction economics for our customers. Availability of our Q4000, Eclipse and Mystic Viking, together with the soon to be completed Intrepid (formerly Sea Sorceress), will result in CDI offering the largest permanently deployed fleet of DP vessels in the Gulf of Mexico (GOM).
On the Outer Continental Shelf (OCS) in water depths up to 1,000 feet, we perform traditional subsea services, including air and saturation diving and salvage work. Our subsidiary, Aquatica, Inc., provides full compliment services in the shallow water market from the shore to 300 fsw. The acquisition of the assets of Professional Divers of New Orleans, Inc. early in 2001 added important vessel and offshore personnel capacity. In the OCS "spot market", projects are generally turnkey in nature, short in duration (two to thirty days) and require constant rescheduling and availability of multiple vessels. Fifteen of our vessels perform traditional diving services and six of them support saturation diving. The technical and operational experience of our personnel and the scheduling flexibility offered by our large fleet enables us to manage turnkey projects to satisfy customers' requirements and achieve our targeted profitability. We have also established a leading position in the salvage market by offering customers a number of options to address decommissioning obligations in a cost-efficient manner, particularly in the removal of smaller structures. Our alliance with Horizon Offshore, Inc. provides derrick barge and heavy lift capacity for the removal of larger structures.
In our Production Partnering business, our subsidiary Energy Resource Technology, Inc. ("ERT") is one of a few companies with the skills required to profitably acquire and operate mature natural gas and oil properties in the Gulf. The reservoir engineering and geophysical disciplines of ERT also enabled us to acquire a working interest in the Gunnison prospect, a Gulf Deepwater oil and natural gas exploration project in partnership with the operator Kerr-McGee Oil & Gas Corporation. We anticipate that this investment will both generate significant income in the future and will also help secure utilization for our subsea assets. As this project has now been sanctioned, we are already participating in field development planning and will collaborate with the other working interest owners in executing subsea construction work. We plan to again expand our Partnering strategy through our recent Letter of Intent to participate in the ownership of the Marco Polo production facility. Owning 50% of this proposed tension-leg platform in a joint venture with El Paso Energy Partners, when financed, would be designed to generate good returns and also have upside potential for both our construction work and ERT farm-in opportunities.
Our overall corporate goal has been to increase shareholder value by focusing on strengthening our market position to provide a return which leads our peer group. Our return on capital employed (ROCE) in
2001 was 12% in contrast to the 4% average of our peer group; we have averaged an ROCE of 16% over the past five years versus the 6% average of our peers. We have been able to achieve our ROCE objective by focusing on the following business strengths and strategies:
OUR STRENGTHS
Diversified Fleet of Vessels and ROVs: Our fleet is the largest permanently deployed in the GOM and has one of the most diverse and technically advanced collections of subsea construction, maintenance and decommissioning project capabilities. These comprehensive services provided by our vessels are both complementary and overlapping, enabling us to assure customers the redundancy essential for most projects but especially in the Deepwater. Our new ROV based remote systems capabilities are critical to Deepwater construction and well intervention operations and Canyon's submarine cable burial business provides a platform for international operations and revenue diversification.
Experienced Personnel and Turnkey Contracting: A key element of our growth strategy has been our ability to hire, attract and retain experienced personnel who we believe are the best in the industry at providing turnkey contracting. We believe the recognized skill of our personnel and our successful operating history uniquely position us to capitalize on the trend in the oil and gas industry of increased outsourcing to contractors and suppliers.
Major Provider of Marine Construction Services on the OCS: We believe that our expansion of Aquatica, our alliance with Horizon and our dominant position in the GOM for saturation diving services makes us the largest supplier of such services on the OCS. Depletion of existing reserves, coupled with increased demand for natural gas, should require exploitation and development of OCS reservoirs.
Production Partnering: The strategy of ERT's gas production business differentiates us from our competitors and helps to offset the cyclical nature of our marine construction operations. ERT's acquisition, sale and exploitation programs for mature properties on the OCS will be greatly expanded by the ownership of Deepwater assets such as the Gunnison project and the Marco Polo facility prospect.
Leader in Decommissioning Operations: Over the last decade, we have established a leading position in decommissioning offshore facilities, particularly in the removal of the smaller structures and caissons which make up 52% of the market. We expect demand for decommissioning services to increase due to the significant backlog of platforms and caissons that must be removed in accordance with government regulations.
OUR STRATEGIES
Focusing on the Gulf: We will continue to focus on the GOM basin, where we have provided marine construction services since 1975. We expect natural gas and oil exploration and development activity in the Gulf, particularly in the Deepwater regions, to increase significantly in the next several years.
Capturing a Significant Share of the Deepwater Market: We expect to benefit from the anticipated increase in Deepwater Gulf activity through our expanded fleet of seven DP vessels, the most any company has permanently deployed in the Gulf. Together with our alliance partners, we provide customers integrated solutions which minimize project duration and cost.
Develop Well Operations Niche: We are employing more Deepwater assets, construction techniques and technologies focused upon servicing upstream market niches, such as pre-drilling services, well operations and vessels that offer cost-effective alternatives to services generally provided by drilling rigs. Examples include: the enhanced well intervention and completion design of the Q4000 and Uncle John and; the pipelay and platform support capability of the Eclipse and Intrepid. GOM well operations is a new niche for us. We believe the modification of the Q4000 will prove economically advantageous to our customers needing this service.
Building Alliances to Expand the Scope of Our Services and Technology: We have alliance agreements with a team of domestic and internationally recognized contractors and manufacturers. These alliances enable us to offer state-of-the-art products and services while maintaining our low overhead base.
Maximizing the Value of Mature Natural Gas and Oil Properties: Through ERT, we acquire and produce mature, non-core offshore property interests, offering customers a cost-effective alternative for customers to the decommissioning process. Since its inception in 1992, ERT has delivered a 30% average annual return on its invested capital.
Partnering with Customers: In 2000, we expanded the ERT business strategy to Deepwater prospects through a 15% equity participation in the Gunnison prospect. Total Proven reserves at 2001 year-end grew to 100 BCFe with initial reserves of 76.5 BCFe assigned to our ownership position in Gunnison. Our recently announced Letter of Intent to own 50% of the tension-leg platform at Anadarko's Marco Polo field, when financed, could extend the concept of acquiring oil and gas assets to earn a return while also securing the associated marine construction work.
SUMMARY OF 2001 DEVELOPMENTS
THIS "SUMMARY OF 2001 DEVELOPMENTS" IS INCOMPLETE BY IT NATURE, MAY OMIT MATERIAL INFORMATION, AND IS QUALIFIED IN ITS ENTIRETY BY MORE DETAILED INFORMATION CONTAINED ELSEWHERE IN THIS FORM 10-K, INCLUDING THE FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
By most measures, 2001 was an outstanding year for us even though commodity prices plummeted and a significant increase in offshore construction activity failed to materialize. As a result, we were able to achieve most of our stated 2001 goals, including:
i. Financial: Delivered ROCE of 12%.
ii. Deepwater Contracting: Purchased additional Deepwater assets.
iii. Well Operations: Undertook Q4000 enhancements.
iv. Production Contracting: Gunnison sanctioned and identified our Marco Polo prospect.
v. OCS: Acquired additional assets and extended the Horizon Alliance.
vi. Safety: Implemented an enhanced EHS management system.
In 2001, for a second time, Forbes magazine named us one of America's 200 best small companies. Our ranking was 109th overall, and we were one of only two oilfield service companies to qualify for this year's list. Articles accompanying the October 29 issue note that the sliding economy reshaped what it meant to be among the best small companies. Rankings were based on six equally weighted metrics: return on equity, sales and earnings-per-share growth, each measured over the past five years and the most recent four quarters. As a result, fewer than 1% of eligible companies made this list. We believe our ability to grow sales and earnings through a decline in the market for offshore services, while delivering a five-year average return on capital of 16%, highlights the value of our counter-cyclical strategy. This counter-cyclical strategy, whereby we acquire interests in oil and gas properties to secure the related marine contracting work, provides a natural hedge in energy industry downturns.
HIGHLIGHTS OF 2001 OPERATING DEVELOPMENTS:
2001 was a roller-coaster year in our market for many reasons, including commodity prices. We believe, however, that three basic factors work in favor of our long-term business model: (i) the Deepwater GOM is an oil play with many large projects "on-course" despite the prices; (ii) the decline in natural gas prices should provide ERT and our Production Partnering strategy with more opportunities; and (iii) Gunnison will provide subsea construction work and then production related cash to fund growth.
DEEPWATER CONTRACTING
In anticipation of developments relating to our long-term business plan in the Deepwater, we had success in four areas in 2001: expansion of non-U.S. markets; acquiring more Deepwater vessels; acquiring our ROV
subsidiary, Canyon, and; implementing our Well Operations Group. Overall revenues in this segment were just under $80 million or 35% of our consolidated total revenue (up from 28% in 2000).
Our decision to accelerate regulatory inspections in 2000 proved useful in achieving 87% utilization (vs 56% in 2000) for our deepwater vessels, particularly the Witch Queen and the Uncle John. The Witch Queen worked in Mexican waters for Horizon/Pemex for 14 consecutive months through the third quarter, then mobilized to Trinidad for BP and other customers. The Merlin provided ROV support to the Allseas Lorelay pipelay vessel for its summer campaign and then was involved in the large Nansen/Boomvang project. After her May acquisition, the Mystic Viking was deployed in Mexican waters for the second half of the year. All work was performed well and represents the potential of future growth in these non-U.S. markets.
With GOM work for our vessels available but world construction activity low, we took the opportunity to grow our fleet to service Deepwater projects. The Mystic Viking purchase replaced the Balmoral Sea with more capacity. In October, we announced the purchase of the Eclipse, a large mono-hull with significant deck load capacity. These vessels together with our exiting fleet provide seven world class DP vessels to help assure scheduling flexibility for the technological challenges of Deepwater.
As another part of our Deepwater puzzle, we purchased the ROV business of our new subsidiary, Canyon. Canyon represents an integration which is consistent with our policy of directly controlling all aspects on the critical path of significant projects. As marine construction support in the Gulf of Mexico moves to deeper waters, ROV systems will play an increasingly important role. Canyon currently owns 18 ROV systems and operates seven others in three regions: United States (13), Southeast Asia (8), and the North Sea (4). It also operates eight trenching systems internationally, including four customer-owned units.
In the second and third quarters, our newly assembled team of well operation specialists, working in tandem with Alliance partner Schlumberger from the Uncle John work platform, tackled intervention projects at three subsea wells. Each job involved through-tubing, subsea well decommissioning operations employing slickline, E-line, cementing, coiled tubing and fluid handling services. The Uncle John worked every available day during the year (93% utility) because of her flexibility to perform both well intervention and marine construction operations. We believe this highlights potential market demand for well operations work by the Q4000. Other major well operations projects completed during 2001 include: Conoco -- world's first use of the Schlumberger Sen Tree 3 system as an open water riser system from a DP vessel in a shallow water live well intervention; and FMC -- jointly developed the world's first 15,000 psi intervention riser for operations to 10,000 fsw. In addition, the 2001 Deepwater geotechnical coring campaign with Alliance partner Fugro involved work at Gunnison, Thunderhorse (formerly Crazy Horse), Holstein and Devil's Tower among others.
SHELF CONTRACTING
In our OCS business, Aquatica delivers our services in the shallow water market (from the beach to 300 fsw). In March 2001, Aquatica acquired substantially all of the assets of Professional Divers which included three utility vessels and a four-point moored DSV. OCS revenues increased at a rapid pace during 2001 in response to both a spike in drilling activity and the doubling of our DSV fleet for a second year in a row -- this time from five vessels to ten. The call-out nature of this business allows us to adjust rates quickly as market conditions develop. These factors combined to generate $37 million of 2001 revenues, an 80% improvement over the prior year.
In early 2001, our OCS Alliance with Horizon Offshore was extended for three years. Under the Alliance, we provide DSVs to support Horizon pipelay barges while Horizon supplies, derrick barge and heavy lift capacity to us. In addition, we took over all Horizon barge diving effective May 1, a low-margin activity we view as a contribution to the success of the alliance. Three of our DSVs work the Outer Continental Shelf virtually all in support of Horizon pipelay activity. This alliance and our work together in Mexico resulted in Horizon becoming our largest customer, accounting for 18% of revenues in 2001.
For the second consecutive year OCS salvage revenues and margins were disappointing. In part, this is a result of high commodity prices in 2000 that led producers to push the last possible production out of their older properties. Because of the decline in commodity prices during 2001, these properties are now appearing
on the market with negative asset values. As a result, we expect that many will go directly to decommissioning, a development that suggests increased salvage demand in 2002 and 2003.
Finally, we introduced a company-wide effort to enhance our behavioral safety process (BSP) and training that makes safety a constant focus of awareness through open communication with all offshore and yard employees. First year results from this program were impressive as our safety rating improved dramatically in 2001.
PRODUCTION PARTNERING
This segment which differentiates us from our Peer Group, was part of the 2001 commodity based roller-coaster. In the first part of the year, ERT contributed significantly to our earnings due to high production and realized gas prices before prices collapsed in the second half. Gas and oil revenues of $63.4 million declined by 10% with virtually all of that attributable to production of 13.9 BCFe versus 15.5 BCFe the prior year. Fortunately, production was at the high end of our expectation (14BCFe) without the benefit of significant acquisitions. ERT's management team did an outstanding job conducting an aggressive and successful exploitation program resulting in near replacement of reserves. 2001 closed with 24.5 BCFe of proven reserves in contrast to 28.2 BCFe a year earlier.
Also in 2001, our Deepwater ERT plan succeeded as initial reserves of 76.5 BCFe were assigned to our ownership position in Gunnison. This figure represents 15% of the reserves reported by the operator, Kerr-McGee Oil & Gas Corporation, at December 31, 2001. The affiliated limited partnership that assumed the exploratory risk funded $21.5 million of drilling costs, considerably above the initial $15 million estimate. Our share of the ensuing project development costs is estimated in a range of $100 million to $110 million with over half of that for construction of the spar. The full potential of the three Gunnison blocks will be better defined a year from now as the operator plans an extensive development program in 2002. The development timetable schedules our marine construction activities for 2003 with first production anticipated early in 2004. The field is now expected to begin production in 2004.
During 2001 we took another step to expanding our Production Partnering concept by signing a Letter of Intent to own 50% of the Marco Polo production facility at 4300 fsw. When financed, we would assist with the installation of the tension-leg platform which would be operated with El Paso Energy Partners on a fixed-fee-plus-tariff basis.
INTRODUCTION TO SUBSEA CONSTRUCTION
The offshore oilfield services industry in the Gulf originated in the early 1950s to assist companies as they began to explore and develop offshore fields. The industry has grown significantly since the early 1970s as the domestic natural gas and oil industry has increasingly relied upon these fields for new production. The oilfield services industry benefits from a number of trends including the following:
- Lack of growth in natural gas production and failure to construct new assets in the face of foreign dependency and increasing demand.
- Advances in exploration, extraction and production technology that have enabled industry participants to more cost-effectively enter the Gulf Deepwater.
- Increased demand for decommissioning services as the offshore natural gas and oil continues to mature.
In response to the natural gas and oil industry's migration to the Deepwater, equipment and vessel requirements have changed. Most vessels currently operating in the Deepwater Gulf were designed in the 1970s and 1980s for work in a maximum depth of approximately 1,000 feet. These vessels have been modified to take advantage of new technologies and now operate in depths up to 4,000 feet. We believe there is unmet demand in the Gulf for new generation vessels, such as the Q4000 and Intrepid, that are specifically designed to work in water depths up to 10,000 feet.
Defined below are certain terms and ideas helpful to understanding the services we perform in support of offshore development:
BCFe: When describing oil and natural gas, the term converts oil volumes to their energy equivalent in natural gas and combines them in billions of cubic feet equivalent (BCFe).
Deepwater: Water depths beyond 1,000 feet fsw.
Dive Support Vessel (DSV): Specially equipped vessel which performs services and acts as an operational base for divers, ROVs and specialized equipment.
Dynamic Positioning (DP): Computer-directed thruster systems that use satellite-based positioning and other positioning technologies to ensure the proper counteraction to wind, current and wave forces enable the vessel to maintain its position without the use of anchors. Two DP systems (DP-2) are necessary to provide the redundancy required to support safe deployment of divers, while only a single DP system is necessary to support ROV operations.
DP-2: Redundancy allows the vessel to maintain position even with failure of one DP system. Required for vessels which support both manned diving and robotics, and for those working in close proximity to platforms.
EBITDA: Earnings before interest, taxes, depreciation and amortization is a supplemental financial measure of cash flow used in the evaluation of the marine construction industry.
EHS: Environment, Health and Safety programs that protect the environment, safeguard employee health and eliminate injuries.
E&P: Companies involved in oil and gas exploration and production activities.
Full Field Development: The ability to offer to oil and gas companies a range of services from subcontracting to complete field development solutions. These include procurement and installation of flowlines, wellheads, control systems, umbilicals and manifolds, as well as installation and commissioning of the complete production system. Many oil and gas companies prefer to contract with a company capable of undertaking the entire field development project or major portions of it. Full field development services can relieve a customer of substantial management burdens.
Life of Field Services: Includes services performed on facilities, trees and pipelines from the beginning to the economic end of the life of an oil field, including installation, inspection, maintenance, repair, contract operations, well intervention, recompletion and abandonment.
MBbl: When describing oil, refers to 1,000 barrels containing 42 gallons each.
Minerals Management Service (MMS): The government regulatory body having responsibility for United States waters in the Gulf.
MMcf: When describing natural gas, refers to 1 million cubic feet.
Moonpool: An opening in the center of a vessel through which a saturation diving system or ROV may be deployed, allowing safe deployment in adverse weather conditions.
Outer Continental Shelf (OCS): For purposes of our industry, areas in the Gulf from the shore to 1,000 feet of water.
Peer Group: Defined in this report as comprising Global Industries, Ltd. (Nasdaq: GLBL), Horizon Offshore, Inc. (Nasdaq: HOFF), McDermott International, Inc. (NYSE: MDR), Oceaneering International, Inc. (NYSE: OII), Stolt Offshore SA (Nasdaq: SOSA), Technip-Coflexip (NYSE: TKP), and Torch Offshore, Inc. (Nasdaq: TORC).
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.
ROCE: Return on Capital Employed is the amount, expressed as a percentage, earned on a company's total capital (shareholders' equity plus long-term debt). It is calculated by dividing earnings before interest and dividends by total capital.
Saturation Diving: Saturation diving, required for work in water depths between 300 and 1,000 feet, involves divers working from special chambers for extended periods at a pressure equivalent to the pressure at the work site.
Spar: Floating production facility anchored to the seabed with catenary mooring lines.
Spot Market: Prevalent market for subsea contracting in the Gulf, characterized by projects generally short in duration and often of a turnkey nature. These projects often require constant rescheduling and the availability or interchangeability of multiple vessels.
Subsea Construction Vessels: Subsea services are typically performed with the use of specialized construction vessels which provide an above-water platform that functions as an operational base for divers and ROVs. Distinguishing characteristics of subsea construction vessels include DP systems, saturation diving capabilities, deck space, deck load, craneage and moonpool launching. Deck space, deck load and craneage are important features of the vessel's ability to transport and fabricate hardware, supplies and equipment necessary to complete subsea projects.
Ultra-Deepwater: Water depths beyond 4,000 fsw.
SUBSEA CONTRACTING
We and our alliance partners provide a full range of subsea construction services, including the following, in both the OCS and Deepwater Gulf:
- Exploration. Pre-installation surveys; rig positioning and installation assistance; drilling inspection; subsea equipment maintenance; well completion; search and recovery operations.
- Development. Installation of production platforms; installation of subsea production systems; pipelay support including connecting pipelines to risers and subsea assemblies; pipeline stabilization, testing and inspection; cable and umbilical lay and connection.
- Production. Inspection, maintenance and repair of production structures, risers and pipelines and subsea equipment; well intervention; life of field support.
- Decommissioning. Decommissioning and remediation services; plugging and abandonment services; platform salvage and removal; pipeline abandonment; site inspections.
Deepwater Contracting and Well Operations
In 1994, we began to assemble a fleet of DP vessels in order to deliver subsea services in the Deepwater and Ultra-Deepwater. Our fleet consists of: two (2) semi-submersible DP MSVs (the Q4000 and Uncle John); two (2) construction DP DSVs (the Witch Queen and Mystic Viking); two (2) larger mono-hull pipelay and constructions vessels (the Intrepid and the Eclipse) and two (2) ROV support vessels (the Merlin and the Northern Canyon). In 2001, vessel enhancements included the Q4000 (well completions) and the Intrepid (DP-2 capability and a 400-ton crane). The Q4000 has recently been completed, and both vessels are expected to be working in the second quarter of 2002. When all of our DP vessels begin work, we will have seven world class vessels permanently deployed in the Gulf of Mexico.
With the acquisition of our new subsidiary, Canyon, we have increased our operated ROV and trenching fleet to 26. Our new subsidiary's 18 ROVs are designed for offshore construction (rather than drilling rig support) and its management team adds industry experience in a setting where our vessels can add value in support of its ROVs. As marine construction support in the Gulf of Mexico moves to deeper waters, ROV systems will play an increasingly important role. Canyon currently owns 18 ROV systems and operates seven others in three regions: United States (13), Southeast Asia (8), and the North Sea (4). Canyon's assets will
help to assure our customers of vessel availability and schedule flexibility to meet the technological challenges of Deepwater construction developments in the Gulf and internationally.
With its experienced personnel, our Well Operations Group is intended to support downhole operations of the Uncle John and Q4000. Both vessels provide cost-effective alternatives for Deepwater operations. This business line involves drilling support (which includes pre-setting casings, setting trees and commissioning wells), life-of-field services (which include well intervention), decommissioning and abandonment. Previously there were few cost-effective solutions for subsea well operations to troubleshoot or enhance production, shift zones or perform recompletions, as most all of such work has been done from drill rigs.
We are a leader in solving the operational challenges encountered in the Deepwater projects using methods or technologies we have developed. To enhance our ability to provide both full field development and life of field services, we have alliances with other offshore service and equipment providers. These alliances enable us to offer state-of-the-art products and services while maintaining our low overhead base. These alliances include:
- FMC Corp. -- Well intervention hardware and risers
- Fugro-McClelland Marine Geoscience, Inc. -- Geotechnical coring and survey
- Horizon Offshore, Inc. -- Small diameter reeled pipelay equipment
- Schlumberger Limited -- Deepwater downhole services
- Shell Offshore, Inc. -- Vessels for well intervention
While the DP market remained soft, the significant increase in utilization (87% versus 56% a year ago) reflects improved market share and an expansion in the scope of GOM deepwater installations. Major projects in 2001 were:
Shelf Contracting
In water depths up to 1,000 feet (the OCS), we perform traditional subsea services including air and saturation diving in support of marine construction activities. Fifteen of our vessels perform traditional subsea services, and six support saturation diving. In addition, our highly qualified personnel have the technical and operational experience to manage turnkey projects to satisfy customers' requirements and achieve our targeted profitability.
Aquatica delivers our services in the shallow water market (from the beach to 300 fsw). In March 2001, Aquatica acquired substantially all of the four vessels and business of Professional Divers and doubled the size of our DSV fleet. We also perform numerous projects on the OCS in an alliance with Horizon Offshore, Inc. In the late 1980's we demonstrated that pipelay operations would be much more effective if the expensive barge spreads simply laid the pipe, allowing our DSVs to follow along and perform the more time-consuming task of commissioning the line. Principal features of the Alliance are that we have the exclusive right to provide DSV services behind Horizon pipelay barges while Horizon supplies pipelay, derrick barge and heavy lift capacity to Cal Dive. The recent expansion of the Alliance also resulted in our providing the diving personnel working from Horizon barges, a service Horizon handled internally last year. Our interaction with Horizon is multi-faceted, including operations in addition to those that flow from the formal alliance to provide services on the OCS. For example, much of our work in Mexican waters has been subcontracted from Horizon.
Since 1989, we have undertaken a wide variety of decommissioning assignments, mostly on a turnkey basis. A recently revised study by the MMS estimates that the total cost of the GOM abandonment market is $8.0 billion. Cal Dive has established a leading position in the removal of smaller structures, such as caissons and well protectors, which represent 52% of the structures in the Gulf.
PRODUCTION PARTNERING
We formed ERT in 1992 to exploit a market opportunity to provide a more efficient solution to offshore abandonment. Its business plan has evolved into the concept of Production Partnering, the business segment that differentiates us from our competitors. Production Partnering offers customers the option of selling mature offshore fields and also expands our off-season salvage and decommissioning activity to enable us to support full field production development projects. The business advantages of our production business are fourfold. First, the financial smoothing of oil and gas revenues counteracts the lumpiness and the extreme volatility in the revenues and income which most offshore construction companies have reported in the past three years. In periods of excess capacity such as 2001, we have the flexibility to stay out of the competitive bid market, focusing instead upon negotiated contracts. Third, our oil and gas operations generate significant cash flow that has funded construction of assets such as the Q4000, Intrepid and Eclipse while enabling us to add technical talent to support our expansion into the new Deepwater frontier. Finally, the primary objective of each CDI investment in oil and gas properties is to secure the associated marine construction work.
Within ERT, we have assembled a team of personnel with experience in geology, geophysics, reservoir engineering, drilling, production engineering, facilities management and lease operations. ERT makes its money in three ways: lowering salvage costs by using our assets, operating the field more cost effectively and extending reservoir life through well exploitation operations. The periodic collapses of commodity prices in the last few years removed some of the small companies which buy mature properties. In the past two years, however, two competitors have captured significant market share. In the face of this competition, our disciplined strategy resulted in completing only three small mature property acquisitions in 2001, as high commodity prices made such purchases difficult. Rather than chase the upcycle and pay too much for properties, our emphasis turned internally to extracting more value from the existing property base. ERT designed and executed a significant well enhancement program that resulted in adding 8.2 BCFe to proved reserves at a cost of $1.06 per Mcf.
There are 142 announced commercial discoveries in the deepwater GOM that have yet to be brought into production. Many of these are smaller reservoirs that standing alone cannot justify the economics of a host production facility. As a result we expect that the Deepwater GOM will be developed in a hub and satellite field concept that resembles the approach the airline industry has used with regional hub locations. We see significant opportunities as this occurs. For example, Gunnison, our first Deepwater field development project, is a hub location where we will provide infrastructure and tie-back marine construction services. At the Marco Polo field, although final agreements and financing have not been agreed, our 50% ownership in the production facility would allow Cal Dive to realize a transmission return. In addition we seek to assist with the installation of the TLP and then work to develop the surrounding acreage which can be tied back to the platform by CDI construction vessels.
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. The percent of consolidated revenue of major customers was as follows: 2001-Horizon Offshore, Inc. (18%), Enron Corporation (10%); 2000-Enron Corporation (13%); and 1999-EEX Corporation (13%). We estimate that in 2001 we provided subsea services to over 211 customers. Our projects are typically of short duration and are
generally awarded shortly before mobilization. Accordingly, we believe backlog is not a meaningful indicator of future business results.
COMPETITION
The subsea services industry is highly competitive. While price is a factor, the ability to utilize specialized vessels, to attract and retain skilled personnel and to demonstrate a good safety record are also important. Our competitors on the OCS include Global Industries Ltd., Oceaneering International, Inc., Stolt Offshore S.A., Torch Offshore, Inc., and a number of smaller companies, some of which only operate a single vessel and often compete solely on price. For Deepwater projects, our principal competitors include Global Industries Ltd., Oceaneering International, Inc., Stolt Offshore S.A., and Technip-Coflexip. Other foreign-based subsea contractors, including DSND Ltd., Rockwater, Ltd. and Saipem S.p.A., may periodically perform services in the Gulf.
ERT encounters significant competition for the acquisition of mature natural gas and oil properties. Two such competitors are Tetra Technologies, Inc. and Offshore Specialty Fabricators. Our ability to acquire additional properties depends upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our competitors are well-established companies with substantially larger operating staffs and greater capital resources.
TRAINING, SAFETY AND QUALITY ASSURANCE
As work levels increase on the OCS, safety, our single most important objective, will be even more important because the projects in these water depths are more personnel-intensive. Over 35 years Cal Dive has continuously upgraded and revitalized so that environment, health and safety (EHS) at work are embraced as core business values. Our Executive EHS Steering Committee, chaired by the President and Vice Presidents, meets monthly to decide on strategy and action plans for improvements. Our behavioral safety process (BSP) empowers employees to take control of their own safety at work using proven techniques of employees observing each other for correct and safe behavior. During 2001, we introduced a company-wide program to enhance the BSP and training that makes safety a constant focus of awareness through open communication with all offshore and yard employees. 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. We are subject to the jurisdiction of the Coast Guard, the Environmental Protection Agency, MMS and the U.S. Customs Service, as well as private industry organizations such as the American Bureau of Shipping.
We support and voluntarily comply with standards of the Association of Diving Contractors International. The Coast Guard sets safety standards and is authorized to investigate vessel and diving accidents, and to recommend improved safety standards. The Coast Guard also is authorized to inspect vessels at will. We are required by various governmental and quasi-governmental agencies to obtain various permits, licenses and certificates with respect to our operations. We believe that we have obtained or can obtain all permits, licenses and certificates necessary for the conduct of our business.
In addition, we depend on the demand for our services from the oil and gas industry and, therefore, our business is affected by laws and regulations, as well as changing taxes and policies relating to the oil and gas industry generally. In particular, the development and operation of natural gas and oil properties located on the OCS of the United States is regulated primarily by the MMS.
The MMS requires lessees of OCS properties to post bonds in connection with the plugging and abandonment of wells located offshore and the removal of all production facilities. Operators on the OCS are currently required to post an area-wide bond of $3.0 million, or $500,000 per producing lease. We currently
have bonded our offshore leases as required by the MMS. Under certain circumstances, the MMS has the authority to suspend or terminate operations on federal leases. Any such suspensions or terminations of our operations could have a material adverse effect on our financial condition and results of operations.
We acquire production rights to offshore mature natural gas and oil properties under federal natural gas and oil 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). These MMS directives are subject to change. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has issued regulations restricting the flaring or venting of natural gas and prohibiting the burning of liquid hydrocarbons without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. Finally, under certain circumstances, the MMS may require any operations on federal leases to be suspended or terminated. In December 1999, the MMS issued regulations that would allow it to expel unsafe operators from existing OCS platforms and bar them from obtaining future leases.
Under the OCSLA, MMS also administers oil and gas leases and establishes regulations that set the basis for royalties on oil and gas produced from the leases. The MMS amends these regulations from time to time. For example, on March 15, 2000, the MMS issued a final rule governing the calculation of royalties and the valuation of crude oil produced from federal leases. The rule modifies the valuation procedures for both arm's length and non-arm's length crude oil transactions to decrease reliance on oil posted prices and assign a value to crude oil that better reflects market value. The rule has been challenged by two industry trade associations and is currently under judicial review in the United States District Court for the District of Columbia. In addition, the MMS recently issued a final rule amending its regulations regarding costs for natural gas transportation which are deductible for royalty valuation purposes when natural gas is sold off-lease. 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. A United States District Court, however, enjoined substantial portions of this rule on March 28, 2000. The United States appealed the district court decision and the case is pending before the Court of Appeals for the District of Columbia Circuit.
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 (NGPA) and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (FERC). In the past, the federal government has regulated the prices at which natural gas and oil could be sold. While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids currently can be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended the NGPA to remove both price and non-price controls from natural gas sold in "first sales" no later than January 1, 1993.
Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC jurisdiction. These initiatives may also affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot be predicted. 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 but we do not believe any such action will materially affect CDI differently than other companies with which we compete.
Additional proposals and proceedings before various federal and state regulatory agencies and the courts could affect the natural gas and oil 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 our capital expenditures, earnings or competitive position.
ENVIRONMENTAL REGULATION
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. Under these laws and regulations, we may be liable for remediation or removal costs, damages and other costs associated with releases of hazardous materials including oil into the environment, and such liability may be imposed on us even if the acts that resulted in the releases were in compliance with all applicable laws at the time such acts were performed.
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, a vessel or a pipeline, and the lessee or permittee of the area in which an offshore facility is located. OPA imposes liability on each responsible party for oil spill removal costs and for other public and private damages from oil spills. Failure to comply with OPA may result in the assessment of civil and criminal penalties. OPA establishes liability limits of $350 million for onshore facilities, all removal costs plus $75 million for offshore facilities and the greater of $500,000 or $600 per gross ton for vessels other than tank vessels. The liability limits are not applicable, however, if the spill is caused by gross negligence or willful misconduct, if the spill results from violation of a federal safety, construction, or operating regulation, or if a party fails to report a spill or fails to cooperate fully in the cleanup. Few defenses exist to the liability imposed under OPA. Management is currently unaware of any oil spills for which we have been designated as a responsible party under OPA that will have a material adverse impact on us or our operations.
OPA also imposes ongoing requirements on a responsible party, including preparation of an oil spill contingency plan and maintaining proof of financial responsibility to cover a majority of the costs in a potential spill. We believe we have appropriate spill contingency plans in place. With respect to financial responsibility, OPA requires the responsible party for certain offshore facilities to demonstrate financial responsibility of not less than $35 million, with the financial responsibility requirement potentially increasing up to $150 million if the risk posed by the quantity or quality of oil that is explored for or produced indicates that a greater amount is required. The MMS has promulgated regulations implementing these financial responsibility requirements for covered offshore facilities. Under the MMS regulations, the amount of financial responsibility required for an offshore facility is increased above the minimum amounts if the "worst case" oil spill volume calculated for the facility exceeds certain limits established in the regulations. We believe that we currently have established adequate proof of financial responsibility for our onshore and offshore facilities and that we satisfy the MMS requirements for financial responsibility under OPA and applicable regulations.
OPA also requires owners and operators of vessels over 300 gross tons to provide the Coast Guard with evidence of financial responsibility to cover the cost of cleaning up oil spills from such vessels. We currently own and operate six vessels over 300 gross tons. Satisfactory evidence of financial responsibility has been provided to the Coast Guard for all of our vessels.
The Clean Water Act imposes strict controls on the discharge of pollutants into the navigable waters of the U.S. and imposes potential liability for the costs of remediating releases of petroleum and other substances. The controls and restrictions imposed under the Clean Water Act have become more stringent over time, and it is possible that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. Certain state regulations and the general permits issued
under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the exploration for and production of oil and gas into certain coastal and offshore waters. The Clean Water Act provides for civil, criminal and administrative penalties for any unauthorized discharge of oil and other hazardous substances and imposes liability on responsible parties for the costs of cleaning up any environmental contamination caused by the release of a hazardous substance and for natural resource damages resulting from the release. Many states have laws which are analogous to the Clean Water Act and also require remediation of releases of petroleum and other hazardous substances in state waters. Our vessels routinely transport diesel fuel to offshore rigs and platforms and also carry diesel fuel for their own use. Our supply boats transport bulk chemical materials used in drilling activities and also transport liquid mud which contains oil and oil by- products. Offshore facilities and vessels operated by us have facility and vessel response plans to deal with potential spills of oil or its derivatives. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
OCSLA provides the federal government with broad discretion in regulating the production of offshore resources of natural gas and oil, including authority to impose safety and environmental protection requirements applicable to lessees and permittees operating in the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and cancellation of leases. Because our operations rely on offshore oil and gas exploration and production, if the government were to exercise its authority under OCSLA to restrict the availability of offshore oil and gas leases, such action could have a material adverse effect on our financial condition and 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 requiring the remediation of releases of hazardous substances into the environment and imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons including owners and operators of contaminated sites where the release occurred and those companies who transport, dispose of or who arrange for disposal of hazardous substances released at the sites. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. Third parties may also file claims for personal injury and property damage allegedly caused by the release of hazardous substances. Although we handle hazardous substances in the ordinary course of business, we are not aware of any hazardous substance contamination for which we may be liable.
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 our capital expenditures, earnings or competitive position. However, changes in the environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and thus there can be no assurance that we will not incur significant environmental compliance costs in the future.
EMPLOYEES
We rely on the high quality of our workforce. As of March 26, 2002, we had 835 employees, 230 of which were salaried. As of that date we also utilized approximately 111 non-U.S. citizens to crew our foreign flag vessels under a crewing contract with C-MAR Services (UK), Ltd. of Aberdeen, Scotland. None of our employees belong to a union or are employed pursuant to any collective bargaining agreement or any similar arrangement. Management believes that our relationship with our employees and foreign crew members is good.
FACTORS INFLUENCING FUTURE RESULTS AND ACCURACY OF FORWARD-LOOKING STATEMENTS
Shareholders should carefully consider the following risk factors in addition to the other information contained herein. This Annual Report on Form 10-K includes certain statements that may be deemed "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. You can identify these statements by forward-looking words such as "anticipate," "believe," "budget," "could," "estimate," "expect," "forecast," "intend," "may," "plan," "potential," "should," "will" and "would" or similar words. You should read statements that contain these words carefully because they discuss our future expectations, contain projections of our future financial position or results of operations or state other forward-looking information. We believe that it is important to communicate our future expectations to our investors. However, there may be events in the future that we are not able to predict or control accurately. The factors listed below in this section, captioned "Factors Influencing Future Results And Accuracy of Forward-Looking Statements," as well as any cautionary language in this Annual Report, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. You should be aware that the occurrence of the events described in these risk factors and elsewhere in this Annual Report could have a material adverse effect on our business, results of operations and financial position.
OUR BUSINESS IS ADVERSELY AFFECTED BY LOW OIL AND GAS PRICES AND BY THE CYCLICALITY OF THE OIL AND GAS INDUSTRY.
Our business is substantially dependent upon the condition of the oil and gas industry and, in particular, the willingness of oil and gas companies to make capital expenditures on offshore exploration, drilling and production operations. The level of capital expenditures generally depends on the prevailing view of future oil and gas prices, which are influenced by numerous factors affecting the supply and demand for oil and gas, including:
- Worldwide economic activity
- 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
- Technological advances
- Interest rates and the cost of capital
- Environmental regulation
- Tax policies
The level of offshore development and production activity did not increase materially in 2001 despite high commodity prices in the first half of the year. We cannot assure you that activity levels will increase anytime 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 occurrences 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. We cannot assure you that any such insurance will be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on us. Moreover, we cannot assure you that we will be able to maintain adequate insurance in the future at rates that we consider reasonable. As construction activity moves into deeper water in the Gulf, 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 the loss of the Balmoral Sea was covered by insurance, the current insurance on our vessels (in some cases, in amounts approximating book value, which is less than replacement value) against property loss due to a catastrophic marine disaster, mechanical failure or collision may not cover a substantial loss of revenues, increased costs and other liabilities, and could have a material adverse effect on our operating performance if we lost any of our large vessels.
OUR CONTRACTING BUSINESS DECLINES IN WINTER, AND BAD WEATHER IN THE GULF CAN ADVERSELY AFFECT OUR OPERATIONS.
Marine operations conducted in the Gulf are seasonal and depend, in part, on weather conditions. Historically, we have enjoyed our highest vessel utilization rates during the summer and fall when weather conditions are favorable for offshore exploration, development and construction activities, and we have experienced our lowest utilization rates in the first quarter. As is common in the industry, we typically bear the risk of delays caused by some but not all adverse weather conditions. Accordingly, the results of any one quarter are not necessarily indicative of annual results or continuing trends.
IF WE BID TOO LOW ON A TURNKEY CONTRACT WE SUFFER THE CONSEQUENCES.
A majority of our projects are performed on a qualified turnkey basis where described work is delivered for a fixed price and extra work, which is subject to customer approval, is charged separately. The revenue, cost and gross profit realized on a turnkey contract can vary from the estimated amount because of changes in offshore job conditions, variations in labor and equipment productivity from the original estimates, and performance of others such as alliance partners. These variations and risks inherent in the marine construction industry may result in our experiencing reduced profitability or losses on projects.
ESTIMATES OF OUR NATURAL GAS AND OIL RESERVES, FUTURE CASH FLOWS AND ABANDONMENT COSTS MAY BE SIGNIFICANTLY INCORRECT.
This Annual Report contains estimates of our proved natural gas and oil reserves and the estimated future net cash flows therefrom based upon reports prepared for the years ended December 31, 2001, 2000 and 1999. Excluding the Gunnison reserves for the year ended December 31, 2001, these reports were reviewed by Miller and Lents, Ltd. This 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, abandonment costs, 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 and abandonment expenses and quantities of recoverable natural gas and oil reserves may vary substantially from those estimated in these reports. Any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. You should not assume that the present value of future net cash flows from our proved reserves referred to in this Form 10-K is the current market value of our estimated natural gas and oil reserves. In accordance with Securities and Exchange Commission requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. In addition, if costs of abandonment are materially greater than our estimates, they could have an adverse effect on earnings. Proved reserves at December 31, 2001 also included the initial reserves assigned to our ownership position in Gunnison. Since we do not own the seismic data for the three fields this figure represents 15% of the reserves reported by the operator, Kerr-McGee Oil & Gas Corporation.
THE GUNNISON PROSPECT MAY NOT RESULT IN THE EXPECTED CASH FLOWS OR SUBSEA ASSET UTILIZATION WE ANTICIPATE AND COULD INVOLVE SIGNIFICANT FUTURE CAPITAL OUTLAYS.
The Gunnison prospect is subject to a number of assumptions and uncertainties, including estimates of the capital outlays necessary to develop the prospect and the cash flows that we may ultimately derive. We cannot assure you that we will be able to fund all required capital outlays or that these outlays will be profitable. Moreover, although our working interest entitles us to participate in field development and planning and to collaborate with the other working interest owners in executing subsea construction work, the extent of utilization of our subsea assets for such work has not been determined.
EXPECTED CASH FLOWS FROM THE Q4000 AND INTREPID UPON COMPLETION MAY NOT BE IMMEDIATE OR AS HIGH AS EXPECTED.
These vessels are scheduled to be placed into service in the second quarter of 2002. Additionally delays could also have a material adverse effect on expected utilization for these vessels and our future revenues and cash flows. We will not receive any material increase in revenue or cash flow from either vessel until placed in service. Furthermore, we cannot assure you of customer demand for the Q4000 as that vessel targets the well operations market and, as a result, our future cash flows may be adversely affected. While elements of this vessel design have been patented, new vessels from third parties may also enter the market in the coming years and compete with us for contracts.
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. 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 substantially larger and have greater financial and other resources than we have. If other companies relocate or acquire vessels for operations in the Gulf, levels of competition may increase and our business could be adversely affected.
THE LOSS OF THE SERVICES OF ONE OR MORE OF OUR KEY EMPLOYEES, OR OUR FAILURE TO ATTRACT, ASSIMILATE AND RETAIN OTHER HIGHLY QUALIFIED PERSONNEL IN THE FUTURE, COULD DISRUPT OUR OPERATIONS AND ADVERSELY AFFECT OUR FINANCIAL RESULTS.
The industry has lost a significant number of experienced subsea people over the years due to, among other reasons, the decrease in commodity prices. Our continued success depends on the active participation of our key employees. The loss of our key people could adversely affect our operations. We believe that our success and continued growth are also dependent upon our ability to employ and retain skilled personnel. We believe that our wage rates are competitive; however, unionization or a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in the wage rates we pay, or both. If either of these events occurs for any significant period of time, our revenues and profitability could be diminished and our growth potential could be impaired.
WE MAY NEED TO CHANGE THE MANNER IN WHICH WE CONDUCT OUR BUSINESS IN RESPONSE TO CHANGES IN GOVERNMENT REGULATIONS.
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. We cannot assure you that continued compliance with existing or future laws or regulations will not adversely affect our operations. Significant fines and penalties may be imposed for noncompliance.
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 our shareholders, to fix the rights and preferences on up to 5,000,000 shares of undesignated preferred stock, including dividend, liquidation and voting rights. In addition, our Bylaws divide the Board of Directors into three classes. We are also subject to certain anti-takeover provisions of the Minnesota Business Corporation Act. We also have employment contracts with all of our senior officers which require cash payments in the event of a "change of control." Any or all of the provisions or factors described above may have the effect of discouraging a takeover proposal or tender offer not approved by management and the board of directors and could result in shareholders who may wish to participate in such a proposal or tender offer receiving less for their shares than otherwise might be available in the event of a takeover attempt.
ITEM 2.
ITEM 2. PROPERTIES
OUR VESSELS
We own and operate a fleet of 23 vessels and 19 ROVs. Management believes that the GOM market requires specially designed and/or equipped vessels to competitively deliver subsea construction services. Seven of our vessels have DP capabilities specifically designed to respond to the Deepwater market requirements. Six of our vessels have the capability to provide saturation diving services. Recent developments in our fleet include:
Q4000: In September 1999, we began construction of our newest Deepwater MSV, the Q4000. The vessel has been constructed at an estimated cost of $180 million and incorporates our latest semi-submersible technologies, including various patented elements such as the absence of lower hull cross bracing. Variable deck load of 3,400 metric tons upgraded well completions capability make the vessel particularly well suited for large offshore construction projects in the Ultra-Deepwater. Its Huisman-Itrec multi-purpose tower has an open face which allows free access from three sides, an advantage for a construction and intervention vessel. Another important feature of the Q4000 will be the new intervention riser system we are developing and jointly funding with FMC Corporation. This system will be the first in the industry rated for working pressures to 15,000 pounds per square inch in 10,000 fsw. The Q4000 will be in service in the second quarter of 2002.
Intrepid: CDI is currently in the final stages of converting the former Sea Sorceress. While we refer to this as a conversion, the work constitutes the construction of new DP-2 pipelay vessel into the hull of our ice class vessel acquired three years ago. She will offer customers a construction vessel capable of carrying an 8,000 metric ton deckload. We expect her to be available for work the second quarter of 2002.
Mystic Viking: The DPDSV is 240 feet long and 52 feet wide. Her class is similar to the Witch Queen with DP-2 redundancy, 500 ton load, 2 cranes and a 12 foot x 12 foot moonpool. This vessel was acquired in May of 2002.
Eclipse: This large DPDSV is 370 feet long and 67 feet wide. She has recently been outfitted with her original marine construction features by installing a SAT diving system, restoring the ballast system and upgrading to DP-2. The Eclipse began work in March 2002.
Northern Canyon: Canyon Offshore will take delivery of this purpose built, 270 foot state-of-the-art ROV support vessel which will be deployed initially in the North Sea.
Robotics: To enable us to control critical path equipment involved in our deepwater projects, we acquired Canyon at the end of 2001. Canyon Offshore currently owns 18 ROVs and operates 7 trenching
systems. In 2001, Canyon introduced the next-generation work-class ROV, the Quest. Advantages of the Quest include: electric instead of hydraulic systems, 50% smaller footprint, fewer moving parts (i.e. lower operating costs), a dynamic positioning system and improved depth rating. The average age of the Canyon ROV fleet is approximately two years.
LISTING OF VESSELS, BARGE AND ROVS
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(1) Under government regulations and our insurance policies, we are required to maintain our vessels in accordance with standards of seaworthiness and safety set by government regulations and classification organizations. We maintain our fleet to the standards for seaworthiness, safety and health set by the 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.
(2) In March 2001, CDI acquired substantially all of the assets of Professional Divers of New Orleans, Inc. including the Mr. Sonny (a 165-foot four-point moored DSV), three utility vessels and associated diving equipment including two saturation diving systems.
(3) This leased vessel is under construction and should be available June 15, 2002.
We incur routine drydock inspection, maintenance and repair costs pursuant to Coast Guard regulations and in order to maintain ABS or DNV classification for our vessels. In addition to complying with these requirements, we have our own vessel maintenance program which management believes permits us to continue to provide our customers with well maintained, reliable vessels. In the normal course of business, we charter other vessels on a short-term basis, such as tugboats, cargo barges, utility boats and dive support vessels. All of our vessels are subject to ship mortgages to secure our $60.0 million revolving credit facility with Fleet Credit Corporation, except the Northern Canyon (which will be leased) and the Q4000 (which is subject to liens to secure the MARAD financing).
SUMMARY OF NATURAL GAS AND OIL RESERVE DATA
The table below sets forth information, as of December 31, 2001, with respect to estimates of net proved reserves and the present value of estimated future net cash flows at such date for ERT (not including Gunnison), prepared by Company engineers in accordance with guidelines established by the Securities and Exchange Commission. Our estimates have been reviewed by Miller and Lents, Ltd., independent petroleum engineers.
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(1) The standardized measure of discounted future net cash flows attributable to our reserves was prepared using constant prices as of the calculation date, discounted at 10% per annum. As of December 31, 2001, ERT owned (not including Gunnison) an interest in 122 gross (102 net) natural gas wells and 104 gross (79 net) oil wells located in federal offshore waters in the Gulf of Mexico.
(2) Total proven reserves at year-end grew to 100 BCFe with initial reserves of 76.5 BCFe assigned to our ownership position in Gunnison. This figure represents 15% of the reserves reported by the operator, Kerr-McGee Oil & Gas Corporation, at December 31, 2001.
FACILITIES
Our headquarters is 400 N. Sam Houston Parkway E., 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
We also have sales offices in Lafayette and Harvey, Louisiana.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
INSURANCE AND LITIGATION
Our operations are subject to the inherent risks of offshore marine activity, including accidents resulting in personal injury and the loss of life or property, environmental mishaps, mechanical failures, fires and collisions. We insure against these risks at levels consistent with industry standards. We also carry workers' compensation, maritime employer's liability, general liability and other insurance customary in our business. All insurance is carried at levels of coverage and deductibles that we consider financially prudent. Our services are provided in hazardous environments where accidents involving catastrophic damage or loss of life could occur, and litigation arising from such an event may result in our being named a defendant in lawsuits asserting large claims. To date, we have been involved in only one such claim, where the cost of the Balmoral Sea was covered by insurance. Although there can be no assurance that the amount of insurance we carry is sufficient to protect us fully in all events (or that such insurance will continue to be available at current levels of cost or coverage), 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, we entered into a subcontract with Seacore Marine Contractors Limited to provide the Sea Sorceress for subsea excavation in Canada. Seacore was in turn contracted by Coflexip Stena Offshore Newfoundland Limited, a subsidiary of Coflexip (CSO Nfl), as representative of the consortium of companies contracted to perform services on the project. Due to difficulties with respect to the sea states and soil conditions the contract was terminated. Cal Dive provided Seacore a performance bond of $5 million with respect to the subcontract. No call has been made on this bond. Although CSO Nfl has alleged that the Sea Sorceress was unable to adequately perform the excavation work required under the subcontract, Seacore and we believe the contract was wrongfully terminated and are vigorously defending this claim and seeking damages in arbitration. In another commercial dispute, EEX Corporation sued us and others alleging breach of fiduciary duty by a former EEX employee and damages resulting from certain construction and property acquisition agreements. We have responded alleging EEX Corporation breached various provisions of the same contracts and are seeking a declaratory judgment that the defendants are not liable. Although such litigation has the potential of significant liability, we believe that the outcomes of all such proceedings are not likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows.
ITEM 4.
ITEM 4. SUBMISSION OF MAKERS TO A VOTE OF SECURITY HOLDERS.
None.
ITEM (UNNUMBERED). EXECUTIVE OFFICERS OF THE COMPANY
DIRECTORS, EXECUTIVE OFFICERS AND KEY EMPLOYEES
The executive officers and directors of Cal Dive are as follows:
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(1) Member of Compensation Committee
(2) Member of Audit Committee
(3) Member of Nominating Committee
(4) Member of Executive Committee
Our Bylaws provide for the Board of Directors to be divided into three classes of directors, with each class to be as nearly equal in number of directors as possible, serving staggered three-year terms. The terms of the Class III directors, Gordon Ahalt and Martin R. Ferron, expire in 2002. The terms of the Class II directors, S. James Nelson, Jr. and William L. Transier, expire in 2003. The terms of the Class I directors, Owen Kratz and Bernard Duroc-Danner, expire in 2004. Each director serves until the end of his or her term or until his or her successor is elected and qualified.
Owen Kratz is Chairman and Chief Executive Officer of Cal Dive International, Inc. He was appointed Chairman in May 1998 and has served as the Company's Chief Executive Officer since April 1997. Mr. Kratz served as President from 1993 until February 1999, and as a Director since 1990. He served as Chief Operating Officer from 1990 through 1997. Mr. Kratz joined the Company in 1984 and has held various offshore positions, including saturation (SAT) diving supervisor, and has had management responsibility for client relations, marketing and estimating. From 1982 to 1983, Mr. Kratz was the owner of an independent marine construction company operating in the Bay of Campeche. Prior to 1982, he was a superintendent for Santa Fe and various international diving companies, and a saturation diver in the North Sea.
Martin R. Ferron has served on our Board of Directors since September 1998. Mr. Ferron became President in February 1999 and has served as Chief Operating Officer since January 1998. Mr. Ferron has 20 years of experience in the oilfield industry, including seven in senior management positions with the international operations of McDermott Marine Construction and Oceaneering International Services, Limited. Mr. Ferron has a civil engineering degree, a master's degree in marine technology, an MBA and is a chartered civil engineer.
S. James Nelson, Jr. is Vice Chairman and has been a Director of the Company since 1990. Prior to October 2000, he was Executive Vice President and Chief Financial Officer. From 1985 to 1988, Mr. Nelson was the Senior Vice President and Chief Financial Officer of Diversified Energies, Inc., the former parent of the Company, 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 an undergraduate degree from Holy Cross College (B.S.) and an MBA from Harvard University; he is also a Certified Public Accountant.
Andrew C. Becher has served as Senior Vice President, General Counsel of Cal Dive since January 1996 and became Corporate Secretary in 1998. Mr. Becher served as outside general counsel for Cal Dive from 1990 to 1996, while a partner with the national law firm of Robins, Kaplan, Miller & Ciresi of Minneapolis. From 1987 to 1990, Mr. Becher was Senior Vice President -- Mergers and Acquisitions of Dain Rauscher, Inc., an investment banking firm. From 1976 to 1987, he was a partner specializing in mergers and acquisitions with the law firm of Briggs and Morgan of Minneapolis.
A. Wade Pursell is Senior Vice President and Chief Financial Officer of Cal Dive International, Inc. In this capacity, which he was appointed to in October 2000, Mr. Pursell oversees the treasury, accounting, information technology, tax, administration and corporate planning functions. He joined the Company in May 1997, as Vice President -- Finance and Chief Accounting Officer. From 1988 through 1997 he was with Arthur Andersen LLP, lastly as an Experience Manager specializing in the offshore services industry (which included servicing the Cal Dive account from 1990 to 1997). Mr. Pursell received an undergraduate degree (BS) from the University of Central Arkansas and is a Certified Public Accountant.
Michael V. Ambrose is Senior Vice President -- Deepwater Contracting. His previous experience includes worldwide operations manager for McDermott Underwater Services, Inc. (MUS) from 1994 to 1997, and general manager of operations for Offshore Petroleum Divers (OPD) from 1993 to 1994. Mr. Ambrose's international experience was obtained from 1991 to 1993, while serving as operations manager and setting up offices in Southeast Asia and India for OPD's international managerial expansion. Mr. Ambrose served in Vietnam from 1965 to 1969 as a member of the United States Navy SEAL Team I.
Gordon F. Ahalt has served on our Board of Directors since July 1990 and has extensive experience in the oil and gas industry. Since 1982, Mr. Ahalt has been President of GFA, Inc., a petroleum industry management and financial consulting firm. From 1977 to 1980, he was President of the International Energy Bank, London, England. From 1980 to 1982, he served as Senior Vice President and Chief Financial Officer of Ashland Oil Company. Previously, Mr. Ahalt spent a number of years in executive positions with Chase Manhattan Bank. Mr. Ahalt serves as a director of The Houston Exploration Co., the Bancroft & Elsworth Convertible Funds and other investment funds.
Bernard J. Duroc-Danner has served on our Board of Directors since February 1999. Mr. Duroc-Danner is the Chairman, CEO and President of Weatherford International, Inc., an oilfield service company. Mr. Duroc-Danner also serves as Chairman of the Board of Grant Prideco and as a director of Parker Drilling Company, a provider of contract drilling services and Universal Compression, a provider of a rental, sales, operations, maintenance and fabrication services and products to the domestic and international natural gas industry. Mr. Duroc-Danner holds a Ph.D in economics from the Wharton School (University of Pennsylvania).
William Transier has served on our Board of Directors since October 2000. He is Executive Vice President and Chief Financial Officer for Ocean Energy, Inc. and oversees treasury, investor relations, human resources, and marketing and trading. He assumed his current position in 1999 following the merger of Ocean Energy and Seagull Energy Corporation. Previously, Mr. Transier served as Executive Vice President and Chief Financial Officer for Seagull and in the audit department of KPMG LLP. Mr. Transier received an undergraduate degree from the University of Texas and a master's in business administration from Regis University. He is a director of Metals USA.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
Our common stock is traded on the Nasdaq National Market under the symbol "CDIS." The following table sets forth, for the periods indicated, the high and low closing sales prices per share of our common stock:
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* The stock split 2 for 1 effective November 13, 2000. As of March 20, 2002, there were an estimated 3,971 beneficial holders of our common stock.
DIVIDEND POLICY
We have never paid cash dividends on our common stock and do not intend to pay cash dividends in the foreseeable future. We currently intend to retain earnings, if any, for the future operation and growth of our business. Certain of our current financing arrangements restrict the payment of cash dividends under certain circumstances.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The financial data presented below for each of the five years ended December 31, 2001, 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 (in thousands, except per share amounts).
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Natural gas and oil prices, the offshore mobile rig count, and Deepwater construction activity are three of the primary indicators management uses to forecast the future performance of our business. Our construction services generally follow successful drilling activities by six to eighteen months on the OCS and twelve months or longer in the Deepwater arena. The level of drilling activity is related to both short- and long-term trends in natural gas and oil prices. Commodity prices declined significantly in the last half of 1998 and early 1999, resulting in the offshore mobile rig utilization rates 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 as oil prices reached their highest levels since the Gulf War and in early 2001 natural gas prices reached $10.00 per thousand cubic feet (Mcf), pushing the offshore mobile rig utilization rates back to virtually full utilization. However, a slowing world economy and record levels of natural gas in storage drove oil and gas prices down throughout 2001 with natural gas plunging to $2.00 per Mcf by the end of the year. Our primary leading indicator, the number of offshore mobile rigs contracted, is currently running at around 120 rigs employed in the Gulf of Mexico, compared to 180 last year at this time. The Deepwater GOM is principally an oil play with the size of the reservoirs resulting in significant lead times to first production. We are currently tracking 30 fields that will come into our service market, completion and production, principally in the years 2003 and 2004. We have aggressively moved to assemble a world-class fleet of seven DP vessels as we do not believe that there will be enough marine construction capacity to handle this demand.
Product prices impact our natural gas and oil operations in several respects. We seek to acquire producing natural gas and oil properties that are generally in the later stages of their economic life. The potential abandonment liability is a significant consideration with respect to the offshore properties we have purchased to date. Although higher natural gas prices tend to reduce the number of mature properties available for sale, these higher prices typically contribute to improved operating results for ERT, such as in 2000 and the first half of 2001. In contrast, lower natural gas prices, as experienced in early 1999 and late 2001, typically contribute to lower operating results for ERT and a general increase in the number of mature properties available, as occurred during those periods. We have expanded the scope of our gas and oil operations by taking a working interest in Gunnison, a Deepwater development of Kerr-McGee Oil & Gas Corporation which has encountered significant reserves. We are also expanding our Deepwater Hub strategy by agreeing to participate in the ownership of the Marco Polo production facility.
Vessel utilization is historically lower during the first quarter due to winter weather conditions in the Gulf. Accordingly, we plan our drydock inspections and other routine and preventive maintenance programs during this period. During the first quarter, a substantial number of our customers finalize capital budgets and solicit bids for construction projects. The bid and award process during the first two quarters typically leads to the commencement of construction activities during the second and third quarters. As a result, we have historically generated more than 50% (up to 65%) of our marine contracting revenues in the last six months of the year. Our operations can also be severely impacted by weather during the fourth quarter. Our salvage barge, which has a shallow draft, is particularly sensitive to adverse weather conditions, and its utilization rate tends to be lower during such periods. To minimize the impact of weather conditions on our operations and financial condition, we began operating DP vessels and expanded into the acquisition of oil and gas properties. The unique station-keeping ability offered by DP enables these vessels to operate throughout the winter months and in rough seas. Operation of natural gas and oil properties and production facilities tends to offset the impact of weather since the first and fourth quarters are typically periods of high demand and strong prices for natural gas. Due to this seasonality, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters.
CRITICAL ACCOUNTING POLICIES
The results of operations and financial condition of the Company, as reflected in the accompanying financial statements and related footnotes, are subject to management's evaluation and interpretation of
business conditions, changing capital market conditions and other factors which could affect the ongoing viability of the Company's business segments and/or its customers. Management believes the most critical accounting policies in this regard are the estimation of revenue allowance on gross amounts billed and evaluation of recoverability of property and equipment and goodwill balances. These issues require management to make judgments that are subjective in nature, however, management is able to consider and assess a significant amount of historical data and current market data in arriving at reasonable estimates. Another area which requires management to make subjective judgments is that of revenue recognition. CDI's 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.
ERT acquisitions of producing offshore properties are recorded at the value exchanged at closing together with an estimate of its proportionate share of the undiscounted decommissioning liability assumed in the purchase based upon its working interest ownership percentage. In estimating the decommissioning liability assumed in offshore property acquisitions, the Company performs detailed estimating procedures, including engineering studies. The Company follows the successful efforts method of accounting for its interests in natural gas and oil properties. Under the successful efforts method, the costs of successful wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.
NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations, which supersedes Accounting Principles Board (APB) Opinion No. 16, Business Combinations. SFAS 141 eliminates the pooling-of-interests method of accounting for business combinations and modifies the application of the purchase accounting method. The provisions of SFAS 141 were effective for transactions accounted for using the purchase method completed after June 30, 2001. The Company completed no business combination between June 30, 2001 and December 31, 2001. The Company did acquire 85% of Canyon Offshore, Inc. in January 2002 and accounted for the acquisition using the purchase method in accordance with SFAS 141. See further discussion below.
In July 2001, the FASB also issued SFAS No. 142, Goodwill and Intangible Assets, which supersedes APB Opinion No. 17, Intangible Assets. SFAS 142 eliminates the current requirement to amortize goodwill and indefinite-lived intangible assets, addresses the amortization of intangible assets with a defined life and addresses the impairment testing and recognition for goodwill and intangible assets. SFAS 142, which is effective for 2002, will apply to goodwill and intangible assets arising from transactions completed before and after the statement's effective date. We believe adoption of this standard will have an immaterial effect on CDI's financial position and results of operations.
In July 2001, the FASB released SFAS No. 143, Accounting for Asset Retirement Obligations, which is required to be adopted by the Company no later than January 1, 2003. SFAS No. 143 addresses the financial accounting and reporting obligations and retirement costs related to the retirement of tangible long-lived assets. The Company is currently reviewing the provisions of SFAS No. 143 to determine the standard's impact, if any, on its financial statements upon adoption. Among other things SFAS No. 143 will require oil and gas companies to reflect decommissioning liabilities on the face of the balance sheet, something ERT has done since inception on an undiscounted basis.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which is effective for the Company beginning January 1, 2002. SFAS No. 144 supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions relating to the disposal of a segment of a business of APB Opinion
No. 30. The Company believes that the adoption of SFAS No. 144 will not have a material impact on its financial position or results of operations.
The following table sets forth for the periods presented average U.S. natural gas prices, our equivalent natural gas production, the average number of offshore rigs under contract in the Gulf, the number of platforms installed and removed in the Gulf and the vessel utilization rates for each of the major categories of our fleet.
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(1) Average of the monthly Henry Hub cash prices per Mcf, as reported in Natural Gas Week.
(2) Average monthly number of rigs contracted, as reported by Offshore Data Services.
(3) Source: Offshore Data Services; installation and removal of platforms with two or more piles in the Gulf.
(4) Average vessel utilization rate is calculated by dividing the total number of days the vessels in this category generated revenues by the total number of days in each quarter (excluding Aquatica vessels in 1999). During the second quarter of 1999, the Uncle John spent 30 days in drydock undergoing thruster work and inspections. During the second quarter of 2000, the Uncle John spent 47 days in drydock for engine replacement and inspections and the Witch Queen spent 41 days in drydock undergoing regulatory inspections. During the third quarter of 2000, these vessels were out for a combined 105 days for the same reasons.
ITEM 7.
ITEM 7. RESULTS OF OPERATIONS
COMPARISON OF YEAR ENDED DECEMBER 31, 2001 AND 2000
Revenues. During the year ended December 31, 2001, the Company's revenues increased 25% to $227.1 million compared to $181.0 million for the year ended December 31, 2000 with the Subsea and Salvage segment contributing all of the increase. Aquatica revenues increased 80% to $37.0 million for 2001 from $20.6 million in the prior year due, in part, to added capacity as a result of our acquisition of Professional Divers of New Orleans, Inc. in February 2001 and improved OCS activity. Revenues generated from our DP fleet increased 54% to $79.3 million during 2001 compared to $51.4 million in 2000 due mainly to vessel utilization improving from 56% during 2000 to 87%. This increased utility reflects improved CDI market share, an expansion in the scope of Deepwater services provided and expansion into other regions (Mexico and Trinidad).
Natural Gas and Oil Production revenue for the year ended December 31, 2001 decreased 10% to $63.4 million from $70.8 million during the prior year due to a 10% decrease in production from 15.5 Bcfe in 2000 compared to 13.9 Bcfe during 2001. ERT received an average of $4.44 per Mcf for natural gas and $24.54 per Bbl for oil during 2001 compared to $4.04 per Mcf and $28.91 per Bbl in 2000. Oil and condensate represented 30% of ERT's revenues in 2001 versus 27% in 2000.
Gross Profit. Gross profit of $66.9 million for the year ended December 31, 2001 was 21% better than the $55.4 million gross profit recorded in the prior year with Subsea and Salvage contracting gross profit
providing all of the increase and offsetting a $9.1 million decline in Natural Gas & Oil Production gross profit. Subsea and Salvage margins improved from 15% for the year ended December 31, 2000 to 22% during the year ended December 31, 2001 due mainly to the increase in utilization due to increased marine construction activity, even though we earned only 5% margins on $15 million of Nansen/Boomvang volume that was mostly pass-through revenue.
Natural Gas and Oil Production gross profit decreased $9.1 million from $39.3 million in the year ended December 31, 2000 to $30.2 million for the year ended December 31, 2001 due mainly to the aforementioned 10% decline in production, higher amortization rates in 2001 than 2000 and $1.0 million of accounts receivable exposure related to the Enron bankruptcy.
Selling and Administrative Expenses. Selling and administrative expenses were $21.3 million in 2001, which is relatively flat (3% increase) with the $20.8 million incurred during 2000. Given the increased revenues, this tight cost control provided a two point margin improvement (i.e., 9% margin for the year ended December 31, 2001 compared to 11% for the year ended December 31, 2000).
Net Interest (Income) Expense and Other. The Company reported net interest expense and other of $1.3 million for the year ended December 31, 2001 in contrast to $554,000 for the prior year as average cash balances (net of MARAD financing) declined during 2001 as compared to 2000 due mainly to costs associated with construction of the Q4000 and the Intrepid conversion.
Income Taxes. Income taxes increased to $15.5 million for the year ended December 31, 2001, compared to $11.6 million in the prior year due to increased profitability. Federal income taxes were provided at the statutory rate of 35% in 2001. However, our deduction of Q4000 construction costs as Research and Development expenditures for federal tax purposes resulted in CDI paying no federal income taxes in 2001 and 2000. Since the deduction of Q4000 construction costs affects financial and taxable income in different years, the entire 2001 and 2000 provisions for federal taxes were reflected as deferred income taxes. In addition, the balance sheet includes a $10.0 million income tax receivable as of December 31, 2000 which reflects our amending prior year tax returns to reflect the deduction of such costs (these tax refunds were received in January 2001).
Net Income. Net income of $28.9 million for the year ended December 31, 2001 was $5.6 million, or 24%, more than 2000 as a result of factors described above.
COMPARISON OF YEAR ENDED DECEMBER 31, 2000 AND 1999
Revenues. During the year ended December 31, 2000, our revenues increased 12% to $181.0 million compared to $161.0 million for the year ended December 31, 1999, with Natural Gas and Oil Production contributing all of the increase. Revenue for Subsea and Salvage decreased from $128.4 million to $110.2 million. Subsea and Salvage contracting revenues include almost $17.1 million of revenues from the addition of the DP vessel Cal Dive Aker Dove and the acquisition of the 55% of Aquatica not previously owned.
Exclusive of these new assets, Subsea and Salvage contributed $35.3 million less in 2000 than it did in 1999, due primarily to the weak GOM construction market in 2000 and eight vessels being out of service during the first half of 2000 for a combined 416 days for U.S. Coast Guard (the Coast Guard or USCG) and American Bureau of Shipping (ABS) inspections and two major DP vessels being out of service a combined total of 105 days during the third quarter of 2000. This compares to three vessels being out of service for a combined 113 days during 1999. In addition, the 2000 salvage market was slower than anticipated as producers retained ownership to milk the last production out of mature fields and to take advantage of the high commodity prices. As a result, revenues from our barge operations (which include the subcontract of Horizon derrick and pipelay barges) were only $12.5 million during 2000 or two-thirds of the prior year. Margins also suffered as too many salvage contractors chased too little work.
Natural Gas and Oil Production revenue for 2000 increased 118% to $70.8 million from $32.5 million during the prior year due to a 74% increase in production from 8.9 Bcfe to 15.5 Bcfe. Production grew as a result of the acquisition of interests in six offshore blocks from EEX Corporation during the first quarter as
well as additional production derived from 1999 property acquisitions (involving a total of 20 offshore blocks) and the 1999 well exploitation program. In addition, we realized an average gas price of $4.03 per Mcf equivalent in 2000, an increase of $1.68, or 71%, over 1999. Oil prices averaged over $29 per barrel and represented 27% of gas and oil revenues in 2000.
Gross Profit. Gross profit of $55.4 million for 2000 was 49% better than the $37.3 million gross profit recorded in the comparable prior year period due mainly to the revenue improvement as well as an eight point improvement in margins (31% in 2000 versus 23% in the prior year). Subsea and Salvage margins declined from 20% for 1999 to 15% for 2000 due partly to the weak market and the additional vessels out of service for regulatory inspections and upgrades. While Aquatica margins remained at roughly the consolidated average of 30%, those of the larger vessels that work from 300 feet out into the Deepwater declined by seven percentage points from the prior year. The newly added Cal Dive Aker Dove represented more than half of the year-over-year decline in the gross profit generated by our DP fleet. The operating loss of this vessel was due to the low level of utilization in 2000 and to the sale/leaseback structure whereby financing cost was reported above the line as a charter cost.
Natural Gas and Oil Production gross profit increased $27.4 million from $11.9 million in 1999 to $39.3 million for 2000 (and margins improved from 37% to 55%) due to the aforementioned production and commodity pricing improvements.
Selling and Administrative Expenses. Selling and administrative expenses were $20.8 million in 2000, a 57% increase over the $13.2 million incurred in 1999 due mainly to improved operating results for ERT, whose incentive plan tracks its operating results ($3.1 million increase), and to the consolidation of Aquatica ($1.4 million increase). The remainder of the increase is due to the addition of personnel to the newly formed Well Operations Group to meet the anticipated demand for our services in the Deepwater market.
Net Interest (Income) Expense and Other. We reported net interest expense and other of $554,000 for 2000 in contrast to $849,000 of net interest income for 1999 as average cash balances declined during 2000 as compared to 1999. This decrease was due mainly to the Company's capital program (Q4000 vessel construction) combined with the recording of goodwill amortization expense beginning in August 1999 upon acquiring the 55% of Aquatica, Inc. that we did not already own. Minority interest added back $866,000 in 2000 compared to $109,000 reduction in 1999 due to the losses recorded in 2000 by the Cal Dive Aker Dove, a vessel which was jointly owned with Aker Maritime.
Income Taxes. Income taxes increased to $11.6 million for 2000, compared to $8.5 million in the prior year due to increased profitability. Federal income taxes were provided at 34% in 2000, slightly below the statutory rate of 35%.
Net Income. Net income of $23.3 million for 2000 was $6.4 million, or 38% more than 1999 as a result of factors described above. Diluted earnings per share increased only 31% reflecting the additional shares issued to acquire Aquatica in the third quarter of 1999 and the shares sold in conjunction with the Secondary Offering (Green Shoe).
LIQUIDITY AND CAPITAL RESOURCES
The Company completed an initial public offering of common stock on July 7, 1997, with the net proceeds of approximately $39.5 million resulting in $15 million of cash on hand after paying off all debt outstanding. The following three years internally generated cash flow funded approximately $164 million of capital expenditures while enabling the Company to remain essentially debt free. During the third quarter of 2000 we closed the long-term MARAD financing for construction of the Q4000 and have drawn $99.5 million on this facility through December 31, 2001. In January 2002, the Maritime Administration agreed to expand the facility to $160 million to include the modifications to the vessel which had been approved during 2001. Through December 31, 2001, we have funded over $137 million of the newbuild vessel's $182 million budgeted construction costs. Significant internally generated cash flow during 2001, coupled with the collection of a $10 million tax refund enabled us to acquire the Mystic Viking (a 240 foot DP vessel), the Eclipse (a 370 foot DP vessel) and Professional Divers of New Orleans, Inc. (PDNO) while maintaining cash
balances of $37.1 million as of December 31, 2001. In January 2002, we acquired approximately 85% of Canyon Offshore, Inc. for cash of $51 million, the assumption of $5 million of net debt and 181,000 shares of CDI common stock (143,000 shares of which were purchased by the Company during the fourth quarter of 2001). As of February 28, 2001, we had $114.4 million of debt outstanding under the MARAD facility and $25.2 million of debt outstanding under our $60 million revolving credit facility. In addition, as of February 28, 2001, we (through a special purpose entity) had drawn $11.3 million on a project financing facility covering CDI's share of costs for the construction of the spar at Gunnison. The Company believes that internally-generated cash flow, borrowings under existing credit facilities and use of project financings along with other debt and equity alternatives will provide the necessary capital to achieve our planned growth.
Operating Activities. Net cash provided by operating activities was $89.1 million during the year ended December 31, 2001, as compared to $53.7 million during 2000. This increase was due mainly to increased profitability and collection of a $10 million tax refund from the Internal Revenue Service (reflected in Changes in Income Taxes Receivable) relating to the deduction of Q4000 construction costs as research and development expenditures for federal tax purposes. Timing of accounts payable payments provided $22.3 million of the increase due mainly to expenses accrued at December 31, 2001 on the Nansen/Boomvang project which carries a large component of pass-through costs. This project also accounted for the significant increase in unbilled revenue at December 31, 2001 ($10.7 million versus $1.9 million at December 31, 2000), as the next scheduled invoicing milestone was achieved in January 2002. This was offset by a $20.3 million decrease in funding from accounts receivable collections during 2001 compared to 2000 as we have extended payment terms to Horizon Offshore. In addition, depreciation and amortization increased $3.8 million to $34.5 million for 2001 due mainly to the depreciation of newly acquired vessels in service.
Net cash provided by operating activities was $53.7 million in 2000, as compared to $25.5 million in 1999. This increase was mainly due to increased profitability as well as $23.6 million of funding from the collection of accounts receivable during 2000 as we collected all amounts due on the EEX Cooper abandonment project (the largest contract in our history) during the first quarter. In addition, depreciation and amortization increased $10.1 million to $30.7 million for 2000 due mainly to ERT depletion associated with increased production levels. These increases, along with the aforementioned deferred tax increase, were partially offset by a $22.2 million reduction in the level of funding from accounts payable and accrued liabilities in 2000 compared to 1999. The 1999 levels increased primarily as a result of year-end accruals with respect to the Q4000 construction project and the EEX project.
Investing Activities. Capital expenditures have consisted principally of strategic asset acquisitions related to the assembly of a fleet of DP vessels, construction of the Q4000, acquisition of Aquatica and PDNO, improvements to existing vessels and the acquisition of offshore natural gas and oil properties. We have consistently targeted the years 2002/2003 as the time when we expect to see a significant acceleration in Deepwater demand. As a result, we incurred $151.3 million of capital expenditures during 2001 compared to $95.1 million during 2000 and $77.4 million during 1999, a level which was over five times the prior year. Included in the $151.3 million of capital expenditures in 2001 was $53 million for the construction of the Q4000, $33 million for the conversion of the Intrepid, $40 million relating to the purchase of two DP vessels (the 240 foot by 52 foot Mystic Viking and the 370 foot by 67 foot Eclipse), and production partnering expenditures of $20 million for initial Gunnison development costs and the ERT 2001 Well Enhancement Program. In addition, in March 2001, CDI acquired substantially all of the assets of PDNO in exchange for $11.5 million. The assets purchased included the Sea Level 21 (a 165-foot four-point moored DSV renamed the Mr. Sonny), three utility vessels and associated diving equipment including two saturation diving systems. This acquisition was accounted for as a purchase with the acquisition price of $11.5 million being allocated to the assets acquired and liabilities assumed based upon their estimated fair values with the balance of the purchase price ($2.8 million) being recorded as excess of cost over net assets acquired (goodwill). Included in the $95.1 million of capital expenditures in 2000 was $61.0 million for the construction of the Q4000 and $8.5 million relating to the conversion of the Intrepid.
ERT purchased working interests of 3% to 75% in four offshore blocks during 2001 in exchange for assumption of the pro-rata share of the decommissioning obligations. In addition, during the first quarter of 2001 ERT purchased a working interest of 55% in Vermilion 201 for $2.5 million from an investment
partnership composed of Company management and industry sources which had funded the drilling of a deep exploratory well. Also, during the first half of 2000, ERT acquired interests in six offshore blocks from EEX Corporation and agreed to operate the remaining EEX properties on the OCS. The acquired offshore blocks include working interests from 40% to 75% in five platforms, one caisson and 13 wells. ERT agreed to a purchase price of $4.9 million, assumed EEX Corporation's pro rata share of the abandonment obligation for the acquired interests and entered into a two-year contract to manage the remaining EEX operated properties. 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. In connection with 2001, 2000 and 1999 offshore property acquisitions, ERT assumed net abandonment liabilities of approximately $3,100,000, $4,200,000 and $19,500,000, respectively.
ERT production activities are regulated by the Federal government and require significant third-party involvement, such as refinery processing and pipeline transportation. We record revenue from our offshore properties net of royalties paid to the Minerals Management Service (MMS). Royalty fees paid totaled approximately $15.2 million, $11.7 million and $4 million for the years ended 2001, 2000 and 1999, respectively. In accordance with Federal regulations that require operators in the Gulf of Mexico to post an area wide bond of $3 million, the MMS has allowed the Company to fulfill such bonding requirements through an insurance policy.
In April 2000, ERT acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corporation. Consistent with CDI's philosophy of avoiding exploratory risk, financing for the exploratory costs (initially estimated at $15 million) was provided by an investment partnership (OKCD Investments, Ltd.), the investors of which are CDI senior management, in exchange for a 25% revenue override of CDI's 20% working interest. CDI provided no guarantees to the investment partnership. At that time, the Board of Directors established three criteria to determine a commercial discovery and the commitment of Cal Dive funds: 75 million barrels (gross) of reserves, total development costs of $500 million consistent with 75 MBOE, and a CDI estimated shareholder return of no less than 12%. Kerr-McGee, the operator, drilled several exploration wells and sidetracks in 3,200 feet of water at Garden Banks 667, 668 and 669 (the Gunnison prospect) and encountered significant potential reserves resulting in the three criteria being achieved during 2001. The exploratory phase was expanded to ensure field delineation resulting in the investment partnership which assumed the exploratory risk funding $20 million of exploratory drilling costs, considerably above the initial $15 million estimate. With the sanctioning of a commercial discovery, the Company will fund its share of ongoing development and production costs estimated in a range of $100 million to $110 million ($15.8 million of which had been incurred by December 31, 2001) with over half of that for construction of the spar. CDI has received a commitment from a financial institution to provide construction funding for the spar, including an option for CDI to convert this loan facility into a long-term (20 year) leveraged lease after the spar is placed in service. See further discussion below.
As part of the process of obtaining funding for the exploratory costs of the Gunnison prospect and Vermilion 201, several outside third parties were solicited. Management believes that the fund structure of these transactions was both consistent with the guidelines and at least as favorable to the Company and ERT as could have been obtained from the third parties.
During each of the past three years ERT has sold its interests in certain fields as well as the platforms and a pipeline. An ERT operating policy provides for the sale of assets when the expected future revenue stream can be accelerated in a single transaction. The net result of these sales was to add two cents, four cents and seven cents to diluted earnings per share in the years 2001, 2000 and 1999, respectively. These sales were structured as Section 1031 "Like Kind" exchanges for tax purposes. Accordingly, the cash received was restricted to use for subsequent acquisitions of additional natural gas and oil properties.
In June 2000, the DP DSV Balmoral Sea caught fire while dockside in New Orleans, LA as the vessel was being prepared to enter drydock for an extended period. The vessel was deemed a total loss by insurance underwriters. Her book value (approximately $7 million) was fully insured as were all salvage and removal costs. Payments from the insurance companies were received during the fourth quarter of 2000.
In December 1999, a Cal Dive-affiliated company (CAHT I) entered into a sale-leaseback of the Cal Dive Aker Dove. Our portion of the proceeds received totaled $20.0 million. The lease was accounted for as an operating lease. Effective April 1, 2001, Coflexip's acquisition of Aker enabled CDI to "put" its interest in CAHT I back to Aker in return for Aker assuming all of CDI's obligations and guarantees under the sale-leaseback.
Financing Activities. We have financed seasonal operating requirements and capital expenditures with internally generated funds, borrowings under credit facilities, the sale of common stock and project financings. In August 2000, the Company closed a $138.5 million long-term financing for construction of the Q4000. This U.S. Government guaranteed financing is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration (MARAD Debt). In January 2002, the Maritime Administration agreed to expand the facility to $160 million to include the modifications to the vessel which had been approved during 2001. At the time the financing closed in 2000, the Company made an initial draw of $40.1 million toward construction costs. During 2001, the Company borrowed $59.5 million on this facility and expects to draw the remaining commitment during 2002. The MARAD Debt will be payable in equal semi- annual installments beginning six months after delivery of the newbuild Q4000 and maturing 25 years from such date. It is collateralized by the Q4000, with CDI guaranteeing 50% of the debt, and bears an interest rate which currently floats at a rate approximating AAA Commercial Paper yields plus 20 basis points (2.25% as of December 31, 2001). For a period up to two years from delivery of the vessel CDI has options to lock in a fixed rate. In accordance with the MARAD Debt agreements, CDI is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements. As of December 31, 2001, the Company was in compliance with these covenants.
Since April 1997, the Company has had a revolving credit facility of $40 million available. The Company drew upon this facility only 134 days during the four years ended December 31, 2001 with maximum borrowing of $11.9 million. The Company had no outstanding balance under this facility as of December 31, 2001. In February 2002, the Company amended this facility, expanding the amount available to $60 million and extending the term three years. This facility is collateralized by accounts receivable and most of the remaining vessel fleet, bears interest at LIBOR plus 125-250 basis points depending on CDI leverage ratios and, among other restrictions, includes three financial covenants (cash flow leverage, minimum interest coverage and fixed charge coverage).
In November 2001, ERT (with a corporate guarantee by CDI) entered into a five-year lease transaction with a special purpose entity owned by a third party to fund CDI's portion of the construction costs ($67 million) of the spar for the Gunnison field. This lease is expected to be accounted for as an operating lease upon completion of the construction, and includes an option for the Company to convert the lease into a long-term (20 year) leveraged lease after construction is completed. As of December 31, 2001, the special purpose entity had drawn down $5.6 million on this facility. Accrued interest cost on the outstanding balance is capitalized to the cost of the facility during construction and is payable monthly thereafter. The principal balance of $67 million is due at the end of five years if the long-term leverage lease option is not taken. The facility bears interest at LIBOR plus 225-300 basis points depending on CDI leverage ratios and includes, among other restrictions, three financial covenants (cash flow leverage, minimum interest coverage and debt to total book capitalization). The Company was in compliance with these covenants as of December 31, 2001.
The following table summarizes the Company's contractual cash obligations as of December 31, 2001 and the scheduled years in which the obligations are contractually due (in thousands):
In January 2002, CDI acquired approximately 85% of Canyon Offshore, Inc. (Canyon), a supplier of remotely operated vehicles (ROVs) and robotics to the offshore construction and telecommunications industries, in exchange for cash of $51 million, the assumption of $5 million of Canyon net debt and 181,000 shares of CDI common stock (143,000 shares of which were purchased by the Company during the fourth quarter of 2001 for $2.6 million). Cal Dive will purchase the remaining 15% at a price to be determined by Canyon's performance during the years 2002 through 2004, a portion of which could be compensation expense. The total purchase price is estimated to range from $66 million to $74 million. The acquisition will be accounted for as a purchase with the acquisition price being allocated to the assets acquired and liabilities assumed based upon their estimated fair values, with the excess being recorded as goodwill, which is initially estimated at approximately $40 million.
In September 2000, CDI completed a Secondary stock offering with Coflexip selling its 7.4 million shares of common stock at $26.31 per share. The over-allotment option was exercised resulting in the Company issuing 609,936 shares of common stock and receiving net proceeds of $14.8 million.
In October 2000, our Board of Directors declared a two-for-one split of CDI's common stock in the form of a 100% stock distribution on November 13, 2000 to all holders of record at the close of business on October 30, 2000. All share and per share data in these financial statements have been restated to reflect the stock split.
The only other financing activity during 2001, 2000 and 1999 represents the exercise of employee stock options.
Capital Commitments. Our Board of Directors has approved a capital budget for 2002 which includes $50 million for the completion of the Q4000 and Intrepid, $65 million for the purchase of Canyon Offshore and the addition of three new Quest ROV units, and approximately $30 million as the equity portion of the construction of the Marco Polo production facility. In addition, it is estimated that CDI will be required to fund $19 million for Gunnison development expenditures in addition to an estimated $34 million which will be funded by the project financing established for the construction of the spar. In December 2001, CDI signed a letter of intent to form a 50-50 venture with El Paso Energy Partners to construct, install and own a Deepwater production hub platform and associated facilities primarily for Anadarko Petroleum Corporation's Marco Polo field discovery at Green Canyon 608 in the Gulf of Mexico. CDI's share of the construction costs is estimated to be $100 million. CDI, along with El Paso, is currently negotiating project financing for this venture, terms of which would include a 30% equity component for CDI.
In connection with our business strategy, we evaluate acquisition opportunities (including additional vessels as well as interests in offshore natural gas and oil properties). No such acquisitions are currently pending.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
A variety of quantitative and qualitative factors affect the operations of the Company. For more information see "Factors Influencing Future Results and Accuracy of Forward-Looking Statements".
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of Cal Dive International, Inc.:
We have audited the accompanying consolidated balance sheets of Cal Dive International, Inc. (a Minnesota corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles 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 financial statements referred to above present fairly, in all material respects, the financial position of Cal Dive International, Inc., and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas February 18, 2002
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2001 AND 2000 (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (IN THOUSANDS)
The accompanying notes are an integral part of these consolidated financial statements.
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 twenty-two 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, well operations, 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 January 2002, the Company expanded its Deepwater services through acquisition of Canyon Offshore, Inc. See footnote 17.
In September 1992, Cal Dive formed a wholly-owned subsidiary, Energy Resource Technology, Inc. (ERT), to purchase non-core producing offshore oil and gas properties and those 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. CDI has expanded the scope of its gas and oil operations by taking a working interest in Gunnison, a Deepwater development of Kerr-McGee Oil & Gas Corporation which has encountered significant reserves. The company is expanding its Deepwater Hub strategy by agreeing to participate in the ownership of the Marco Polo production facility.
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
Through the end of 2001, goodwill was amortized on the straight-line method over its estimated useful life. Accumulated amortization as of December 31, 2001 and 2000 was $1.9 million and $1.2 million, respectively. The Company continually evaluated whether subsequent events or circumstances had occurred which indicated that the remaining useful life of goodwill might warrant revision or that the remaining balance of goodwill might 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.
In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations, which supersedes Accounting Principles Board (APB) Opinion No. 16, Business Combinations. SFAS 141 eliminates the pooling-of-interests method of accounting for business combinations and modifies the application of the purchase accounting method. The provisions of SFAS 141 were effective for transactions accounted for using the purchase method completed after June 30, 2001. The Company had no business combination completed between June 30, 2001 and December 31, 2001.
In July 2001, the FASB also issued SFAS No. 142, Goodwill and Intangible Assets, which supersedes APB Opinion No. 17, Intangible Assets. SFAS 142 eliminates the current requirement to amortize goodwill and indefinite-lived intangible assets, addresses the amortization of intangible assets with a defined life and addresses the impairment testing and recognition for goodwill and intangible assets. SFAS 142, which is effective for 2002, will apply to goodwill and intangible assets arising from transactions completed before and after the statement's effective date. The Company believes adoption of this standard will have an immaterial effect on CDI's financial position and results of operations.
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, the costs of successful wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.
ERT acquisitions of producing offshore properties are recorded at the value exchanged at closing together with an estimate of its proportionate share of the undiscounted decommissioning liability assumed in the purchase based upon its working interest ownership percentage. In estimating the decommissioning liability assumed in offshore property acquisitions, the Company performs detailed estimating procedures, including engineering studies. All capitalized costs are amortized on a unit-of-production basis (UOP) based on the estimated remaining oil and gas reserves. Properties are periodically assessed for impairment in value, with any impairment charged to expense.
In July 2001, the FASB released SFAS No. 143, Accounting for Asset Retirement Obligations, which is required to be adopted by the Company no later than January 1, 2003. SFAS No. 143 addresses the financial accounting and reporting obligations and retirement costs related to the retirement of tangible long-lived assets. The Company is currently reviewing the provisions of SFAS No. 143 to determine the standard's impact, if any, on its financial statements upon adoption. Among other things SFAS No. 143 will require oil and gas companies to reflect decommissioning liabilities on the face of the balance sheet, something ERT has done since inception on an undiscounted basis.
The following is a summary of the components of property and equipment (dollars in thousands):
In July 1999, the CDI Board of Directors approved the construction of the Q4000, a newbuild, ultra-deepwater multi-purpose vessel, for a total estimated cost of $150 million and, in June 2001, approved modification to the original construction contract increasing the total estimated costs to $182 million. Amounts incurred on this project and the conversion of the Intrepid pipelay vessel are included in Construction in Progress ($1.9 million of which is capitalized interest).
The cost of repairs and maintenance of vessels and equipment is charged to operations as incurred, while the cost of improvements is capitalized. Total repair and maintenance charges were $8,501,000, $4,343,000 and $6,031,000 for the years ended December 31, 2001, 2000 and 1999, respectively.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which is effective for the Company beginning January 1, 2002. SFAS No. 144 supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions relating to the disposal of a segment of a business of APB Opinion
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
No. 30. The Company believes that the adoption of SFAS No. 144 will not have a material impact on its financial position or results of operations.
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 earnings per share in accordance with SFAS No. 128, Earnings Per Share. SFAS 128 requires the presentation of "basic" EPS and "diluted" EPS on the face of the statement of operations. Basic EPS is computed by dividing the net income available to common shareholders by the weighted-average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS except that the denominator includes dilutive common stock equivalents, which were stock options, less the number of treasury shares assumed to be purchased from the proceeds with the exercise of stock options.
REVENUE RECOGNITION
The Company earns the majority of its subsea service and salvage contracting revenues during the summer and fall months. Revenues are derived from billings under contracts (which are typically of short duration) that provide for either lump-sum turnkey charges or specific time, material and equipment charges which are billed in accordance with the terms of such contracts. The Company recognizes revenue as it is earned at estimated collectible amounts. Revenue on significant turnkey contracts is recognized on the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. Contract price and cost estimates are reviewed periodically as work progresses and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in the period such losses are determined. Unbilled revenue represents revenue attributable to work completed prior to year-end which has not yet been invoiced. All amounts included in unbilled revenue at December 31, 2001 are expected to be billed and collected within one year.
REVENUE ALLOWANCE ON GROSS AMOUNTS BILLED
The Company bills for work performed in accordance with the terms of the applicable contract. The gross amount of revenue billed will include not only the billing for the original amount quoted for a project but also include billings for services provided which the Company believes are outside the scope of the original quote. The Company establishes a revenue allowance for these additional billings based on its collections history if conditions warrant such a reserve.
MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK
The market for the Company's products and 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: 2001 -- Horizon Offshore, Inc. (18%), Enron Corporation (10%); 2000 -- Enron Corporation (13%); and 1999 -- EEX Corporation (13%).
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In March 2001, CDI and Horizon Offshore, Inc. announced that the Alliance Agreement covering operation on the Outer Continental Shelf was extended for a three-year period. Principal features of the Alliance are that CDI provides Dive Support Vessel services behind Horizon pipelay barges while Horizon supplies pipelay, derrick barge and heavy lift capacity to Cal Dive. The Alliance was also expanded to include CDI providing the diving personnel working from Horizon barges, a service Horizon handled internally in 2000. During 2001 the Company also provided dynamically positioned vessels to support Horizon projects for Pemex in Mexican waters of the Gulf of Mexico.
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
The Company accounts for regulatory (U.S. Coast Guard, American Bureau of Shipping and Det Norske Veritas) related drydock inspection and certification expenditures by capitalizing the related costs and amortizing them over the 30-month period between regulatory mandated drydock inspections and certification. During the years ended December 31, 2001, 2000 and 1999, drydock amortization expense was $3.1 million, $2.2 million and $1.7 million, respectively. This predominant industry practice provides appropriate matching of expenses with the period benefitted (i.e., certification to operate the vessel for a 30-month period between required drydock inspections).
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, 2001, 2000 and 1999, the Company made cash payments for interest charges, net of interest capitalized, of $662,000, $-0- and $-0-, respectively, and made cash payments for federal income taxes of approximately $-0-, $1,800,000 and $4,075,000, respectively.
RECLASSIFICATIONS
Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes to make them consistent with the current presentation format.
3. ACQUISITION OF DEEPWATER VESSELS
In May 2001, Cal Dive acquired a dynamically positioned (DP) marine construction vessel, the Mystic Viking (formerly the Bergen Viking). The 240 foot by 52 foot vessel is DP-2 class, similar to the Witch Queen. The Mystic Viking replaces the Balmoral Sea (lost during 2000) and the Cal Dive Aker Dove (Cal Dive's ownership was transferred to Aker effective April 1, 2001).
In October 2001, Cal Dive announced the acquisition of another DP marine construction vessel, the Eclipse (formerly the C.S. Seaspread). The 370 foot by 67 foot vessel is a sister ship to Coflexip Stena Offshore's Constructor and EMC's Bar Protector. She was sold out of the energy services industry into the telecom cable sector in the early 1990s. Following delivery in the first quarter of 2002, her original marine construction features will be restored by installing a saturation diving system (salvaged from the Balmoral Sea), restoring the ballast system, and upgrading the DP system to DP-2 standards. The total cost of the two
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
vessels acquired and related upgrades will approximate $40 million, the majority of which has been expended as of December 31, 2001.
4. OFFSHORE PROPERTY TRANSACTIONS
ERT purchased working interests of 3% to 75% in four offshore blocks during 2001 in exchange for assumption of the pro-rata share of the decommissioning obligations. In addition, during 2001 ERT purchased a working interest of 55% in Vermilion 201 for $2.5 million (see footnote 5). In 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. ERT agreed to a purchase price 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. Additionally, in April 2000, ERT acquired a 20% interest in Gunnison. See further discussion in footnote 5. During the first four months of 1999, in four separate transactions, ERT acquired interests in 20 blocks and 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 liabilities. In connection with 2001, 2000 and 1999 offshore property acquisitions, ERT assumed net abandonment liabilities estimated at approximately $3,100,000, $4,200,000, and $19,500,000 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 $15.2 million, $11.7 million and $4 million for the years ended 2001, 2000 and 1999, respectively. In accordance with federal regulations that require operators in the Gulf of Mexico to post an area wide bond of $3 million, the MMS has allowed the Company to fulfill such bonding requirements through an insurance policy.
During each of the past three years ERT has sold its interests in certain fields as well as the platforms and a pipeline. An ERT operating policy provides for the sale of assets when the expected future revenue stream can be accelerated in a single transaction. The net result of these sales was to add two cents, four cents and seven cents to diluted earnings per share for the years ending December 31, 2001, 2000 and 1999, respectively. These sales were structured as Section 1031 "Like Kind" exchanges for tax purposes. Accordingly, the cash received was restricted to use for subsequent acquisitions of additional natural gas and oil properties.
5. RELATED PARTY TRANSACTIONS
In April 2000, ERT acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corporation. Consistent with CDI's philosophy of avoiding exploratory risk, financing for the exploratory costs (initially estimated at $15 million) was provided by an investment partnership (OKCD Investments, Ltd.), the investors of which are CDI senior management, in exchange for a 25% revenue override of CDI's 20% working interest. CDI provided no guarantees to the investment partnership. At this time, the Board of Directors established three criteria to determine a commercial discovery and the commitment of Cal Dive funds: 75 million barrels (gross) of reserves, total development costs of $500 million consistent with 75 MBOE, and a CDI estimated shareholder return of no less than 12%. Kerr-McGee, the operator, drilled several exploration wells and sidetracks in 3,200 feet of water at Garden Banks 667, 668 and 669 (the Gunnison prospect) and encountered significant potential reserves resulting in the three criteria being achieved during 2001. The exploratory phase was expanded to ensure field delineation resulting in the investment partnership which assumed the exploratory risk funding over $20 million of exploratory drilling costs, considerably above the initial $15 million estimate. With the sanctioning of a commercial discovery, the Company will fund ongoing development and production costs. Cal Dive's share of
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
such project development costs is estimated in a range of $100 million to $110 million ($15.8 million of which had been incurred by December 31, 2001) with over half of that for construction of the spar. CDI has received a commitment from a financial institution to provide a construction funding for the spar, including an option for CDI to convert this loan facility into a long-term (20 year) leveraged lease after the spar is placed in service. See footnote 10.
During the fourth quarter of 2000 another investment partnership composed of Company management and industry sources funded the drilling of a deep exploratory well at ERT's Vermilion 201 field. Effective January 1, 2001, ERT acquired approximately 55% of this investment partnership's interest in the reserves discovered for $2.5 million.
As part of the process of obtaining funding for the exploratory costs of the above projects, several outside third parties were solicited. Management believes that the structure of these transactions was both consistent with the guidelines and at least as favorable to the Company and ERT as could have been obtained from the third parties.
6. ACQUISITION OF PROFESSIONAL DIVERS OF NEW ORLEANS, INC. (PDNO) AND AQUATICA, INC.
In March 2001, CDI acquired substantially all of the assets of Professional Divers of New Orleans, Inc. (PDNO) in exchange for $11.5 million. The assets purchased included the Sea Level 21 (a 165-foot four-point moored DSV renamed the Mr. Sonny), three utility vessels and associated diving equipment including two saturation diving systems. This acquisition was accounted for as a purchase with the acquisition price of $11.5 million being allocated to the assets acquired and liabilities assumed based upon their estimated fair values with the balance of the purchase price ($2.8 million) being recorded as excess of cost over net assets acquired (goodwill).
In February 1998, CDI purchased a significant minority equity interest in Aquatica, Inc., a shallow water 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, valued the shares of Aquatica, Inc. Effective August 1, 1999, 1.4 million 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). Results of operations for Aquatica, Inc. are consolidated with those of Cal Dive for periods subsequent to August 1, 1999.
7. ACCRUED LIABILITIES
Accrued liabilities consisted of the following (in thousands):
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. LONG-TERM DEBT
In August 2000, the Company closed a $138.5 million long-term financing for construction of the Q4000. This U.S. Government guaranteed financing is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration ("MARAD Debt"). In January 2002, the Maritime Administration agreed to expand the facility to $160 million to include the modifications to the vessel which had been approved during 2001. At the time the financing closed in 2000, the Company made an initial draw of $40.1 million toward construction costs. During 2001, the Company borrowed $59.5 million on this facility and expects to draw the remaining commitment during 2002.
The MARAD Debt will be payable in equal semi-annual installments beginning six months after delivery of the newbuild Q4000 and maturing 25 years from such date. It is collateralized by the Q4000, with CDI guaranteeing 50% of the debt, and bears an interest rate which currently floats at a rate approximating AAA Commercial Paper yields plus 20 basis points (2.25% as of December 31, 2001). For a period up to two years from delivery of the vessel CDI has options to lock in a fixed rate. In accordance with the MARAD Debt agreements, CDI is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements. As of December 31, 2001, the Company was in compliance with these covenants.
Since April 1997, the Company has had a revolving credit facility of $40 million available. The Company drew upon this facility only 134 days during the past four years with maximum borrowing of $11.9 million. The Company had no outstanding balance under this facility as of December 31, 2001. In February 2002, the Company amended this facility, expanding the amount available to $60 million and extending the term three years. This facility is collateralized by accounts receivable and most of the remaining vessel fleet, bears interest at LIBOR plus 125-250 basis points depending on CDI leverage ratios and, among other restrictions, includes three financial covenants (cash flow leverage, minimum interest coverage and fixed charge coverage). As of February 18, 2002, the Company had drawn $22 million under this revolving credit facility. See project financing of Gunnison spar at footnote 10.
9. FEDERAL INCOME TAXES
Federal income taxes have been provided based on the statutory rate of 35 percent adjusted for items which are allowed as deductions for federal income tax reporting purposes, but not for book purposes. The primary differences between the statutory rate and the Company's effective rate are as follows:
Components of the provision for income taxes reflected in the statements of operations consist of the following (in thousands):
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 2001 and 2000, is as follows (in thousands):
CDI effectively paid no federal income taxes in 2001 and 2000 due to the deduction of Q4000 construction costs as research and development for federal tax purposes. The Company paid $1.8 million of federal income taxes during 2000, but the amount was refunded in January 2001 upon completing our research and development analysis and filing for the refund. In addition, we filed amended tax returns for 1998 and 1999, deducting such costs, resulting in refunds of $8.2 million which were collected in January 2001. These amounts were reflected as Income Tax Receivable in the accompanying consolidated balance sheets as of December 31, 2000.
10. COMMITMENTS AND CONTINGENCIES:
LEASE COMMITMENTS
During 1999, CDI acquired an 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 owned 56% of CAHT I and, accordingly, results of operations of this company were consolidated in the accompanying financial statements with Aker's share being reflected as minority interest. In December, 1999 CAHT I entered into a sale-leaseback of the Cal Dive Aker Dove. Cal Dive's portion of the sale proceeds received totaled $20 million. The lease was accounted for as an operating lease. Effective April 1, 2001, Coflexip's acquisition of Aker enabled CDI to "put" its interest in CAHT I back to Aker in return for Aker assuming all of CDI's obligations and guarantees under the sale-leaseback.
In November 2001, ERT (with a corporate guarantee by CDI) entered into a five-year lease transaction with a special purpose entity owned by a third party to fund CDI's portion of the construction costs ($67 million) of the spar for the Gunnison field. This lease is expected to be accounted for as an operating lease upon completion of the construction and includes an option for the Company to convert the lease into a long-term (20 year) leveraged lease after construction is completed. As of December 31, 2001, the special purpose entity had drawn down $5.6 million on this facility. Accrued interest cost on the outstanding balance is capitalized to the cost of the facility during construction and are payable monthly thereafter. The principal balance of $67 million is due at the end of five years if the long-term leverage lease option is not taken. The facility bears interest at LIBOR plus 225-300 basis points depending on CDI leverage ratios and includes, among other restrictions, three financial covenants (cash flow leverage, minimum interest coverage and debt to total book capitalization). The Company was in compliance with these covenants as of December 31, 2001.
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 $2,380,000 at December 31, 2001 with $701,000 due in 2002, $669,000 in 2003, $605,000 in 2004, $135,000 in 2005,
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$135,000 in 2006 and $135,000 thereafter. Total rental expense under these operating leases was $779,000, $721,000 and $673,000 for the years ended December 31, 2001, 2000 and 1999, respectively.
In December 2001, CDI signed a letter of intent to form a 50-50 venture with El Paso Energy Partners to construct, install and own a Deepwater production hub platform and associated facilities primarily for Anadarko Petroleum Corporation's Marco Polo field discovery at Green Canyon 608 in the Gulf of Mexico. CDI's share of the construction costs is estimated to be $100 million. CDI, along with El Paso, is currently negotiating project financing for this venture, terms of which would include a 30% equity component for CDI.
INSURANCE
The Company carries Hull and Increased Value insurance which provides coverage for physical damage to an agreed amount for each vessel. The deductibles are based on the value of the vessel with a maximum deductible of $500,000 on the Q4000. Other vessels carry deductibles between $100,000 and $350,000. The Company also carries Protection and Indemnity insurance which covers liabilities arising from the operation of the vessel and General Liability insurance which covers liabilities arising from construction operations. The deductible on both the P&I and General Liability is $100,000 per occurrence. Onshore employees are covered by Workers' Compensation. Offshore employees, including divers and tenders and marine crews, are covered by an Excess Maritime Employers Liability insurance policy which covers Jones Act exposures and includes a deductible of $50,000 per occurrence. In excess of the liability policies named above, the Company carries various layers of Umbrella Liability for total limits of $135,000,000 excess of primary for all vessels except the Q4000. Total limits on the Q4000 are $160,000,000 excess of primary. The Company's self insured retention on its medical and health benefits program for employees is $50,000 per claim.
In June 2000, the DP DSV Balmoral Sea caught fire while dockside in New Orleans, LA as the vessel was being prepared to enter drydock for an extended period. The vessel was deemed a total loss by insurance underwriters. Her book value (approximately $7 million) was fully insured as were all salvage and removal costs. Payments from the insurance companies were received during the fourth quarter of 2000.
The Company incurs workers' compensation claims in the normal course of business, which management believes are covered by insurance. The Company, its insurers and legal counsel analyze each claim for potential exposure and estimate the ultimate liability of each claim. Amounts accrued and receivable from insurance companies, above the applicable deductible limits, are reflected in other current assets in the consolidated balance sheet. Such amounts were $6,276,000 and $6,133,000 as of December 31, 2001 and 2000, respectively. See related accrued liabilities at footnote 7. The Company has not incurred any significant losses as a result of claims denied by its insurance carriers.
LITIGATION
The Company is involved in various routine legal proceedings primarily involving claims for personal injury under the General Maritime Laws of the United States and Jones Act as a result of alleged negligence. In addition, the Company from time to time incurs other claims, such as contract disputes, in the normal course of business. The Company believes that the outcome of all such proceedings would not have a material adverse effect on its consolidated financial position, results of operations or net cash flows.
In 1998, the Company entered into a subcontract with Seacore Marine Contractors Limited to provide the Sea Sorceress for subsea excavation in Canada. Seacore was in turn contracted by Coflexip Stena Offshore Newfoundland Limited, a subsidiary of Coflexip ("CSO Nfl"), as representative of the consortium of companies contracted to perform services on the project. Due to difficulties with respect to the sea states and soil conditions the contract was terminated. Cal Dive provided Seacore a performance bond of $5 million with respect to the subcontract. No call has been made on this bond. Although CSO Nfl has alleged that the Sea Sorceress was unable to adequately perform the excavation work required under the subcontract, Seacore and
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Company believe the contract was wrongfully terminated and are vigorously defending this claim and seeking damages in arbitration. In another commercial dispute, EEX Corporation sued Cal Dive and others alleging breach of fiduciary duty by a former EEX employee and damages resulting from certain construction and property acquisition agreements. Cal Dive has responded alleging EEX Corporation breached various provisions of the same contracts and is seeking a declaratory judgment that the defendants are not liable. Although such litigation has the potential of significant liability, the Company believes that the outcome of all such proceedings is not likely to have a material adverse effect on its consolidated financial position, results of operations or net cash flows.
11. EMPLOYEE BENEFIT PLANS
DEFINED CONTRIBUTION PLAN
The Company sponsors a defined contribution 401(k) retirement plan covering substantially all of its employees. The Company's contributions are in the form of cash and are determined annually as 50 percent of each employee's contribution up to 5 percent of the employee's salary. The Company's costs related to this plan totaled $595,000, $423,000 and $375,000 for the years ended December 31, 2001, 2000 and 1999, respectively.
STOCK-BASED COMPENSATION PLANS
During 2000, the Board of Directors approved a "Stock Option in Lieu of Salary Program" for the Company's Chief Executive Officer. Under the terms of the program, the participant may annually elect to receive non-qualified stock options (with an exercise price equal to the closing stock price on the date of grant) in lieu of cash compensation with respect to his base salary and any bonus earned under the annual incentive compensation program. The number of options granted is determined utilizing the Black-Scholes valuation model as of the date of grant with a risk premium included. The participant made such election for 2001 and 2000 resulting in a total of 180,000 and 115,000 options being granted during 2001 and 2000, respectively (which includes bonuses earned under the annual incentive compensation program in both years).
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 or 33% per year for a three year period, have a maximum exercise life of three, five or ten years and, subject to certain exceptions, are not transferable.
Effective May 12, 1998, the Company adopted a qualified, non-compensatory Employee Stock Purchase Plan ("ESPP"), which allows employees to acquire shares of common stock through payroll deductions over a six month period. The purchase price is equal to 85 percent of the fair market value of the common stock on either the first or last day of the subscription period, whichever is lower. Purchases under the plan are limited to 10 percent of an employee's base salary. Under this plan 38,849, 25,391 and 22,476 shares of common stock were purchased in the open market at a weighted average share price of $22.22, $21.55 and $12.19 during 2001, 2000 and 1999, respectively.
The above plans 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 2001, 2000 and 1999 would have been $25,879,000, $21,665,000 and $16,218,000,
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
respectively, and the Company's pro forma diluted earnings per share would have been $0.79, $0.67 and $0.53, 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.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used: expected dividend yields of 0 percent; expected lives ranging from three to ten years, risk-free interest rate assumed to be 5.5 percent in 1999, 5.0 percent in 2000 and 4.5 percent in 2001, and expected volatility to be 59 percent in 1999, 62 percent in 2000 and 61 percent in 2001. The fair value of shares issued under the ESPP was based on the 15% discount received by the employees.
All of the options outstanding at December 31, 2001, have exercise prices as follows: 97,554 shares at $3.95, 579,000 at $4.75, 108,520 shares at $10.28, 211,668 shares at $18.00, 119,508 shares at $18.06, 129,000 shares at $19.63, 297,000 shares at $21.88 and 636,996 shares ranging from $6.50 to $26.75 and a weighted average remaining contractual life of 3.98 years.
Options granted in 1999 include 287,278 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 outstanding are as follows:
12. COMMON STOCK
The Company's amended and restated Articles of Incorporation provide for authorized Common Stock of 120,000,000 shares with no par value per share.
During the fourth quarter of 2001, CDI purchased 143,000 shares of its common stock for $2.6 million.
In October 2000, the Board of Directors declared a two-for-one split of CDI's common stock in the form of a 100% stock distribution on November 13, 2000 to all holders of record at the close of business on October 30, 2000. All share and per share data in these financial statements have been restated to reflect the stock split.
In September 2000, CDI completed a Secondary Stock Offering with Coflexip selling its 7.4 million shares of common stock at $26.31 per share. The over-allotment option was exercised resulting in the Company issuing 609,936 shares of common stock and receiving net proceeds of $14.8 million, and the Chief Executive Officer, selling 500,000 shares.
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. BUSINESS SEGMENT INFORMATION (IN THOUSANDS)
The following summarizes certain financial data by business segment:
14. 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).
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
Included in capitalized costs proved developed properties being amortized is the Company's estimate of its proportionate share of decommissioning liabilities assumed relating to these properties. As of December 31, 2001 and 2000, such liabilities totaled $29.3 million and $27.5 million, respectively, and are also reflected as decommissioning liabilities in the accompanying consolidated balance sheets.
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
The following table reflects the costs incurred in oil and gas property acquisition and development activities during the years indicated:
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Proved developed 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, 2001, excluding Gunnison, have been reviewed by Miller and Lents, Ltd., independent petroleum engineers. Reserves attributable to Gunnison rely on the operator's estimate of proved reserves. The Company does not own a license to the geophysical data necessary for assessment of reserves and therefore, must rely on the operator's estimate of proved reserves. All of the Company's reserves are located in the United States. Proved reserves cannot be measured exactly because the estimation of
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1999, 337,500 Bbls. of oil and 284,800 Mcf. of gas were undeveloped. As of December 31, 2000, -0- Bbls. of oil and -0- Mcf. of gas of the Company's proven reserves were undeveloped. As of December 31, 2001, 6,829,000 Bbls. of oil and 35,525,000 Mcf. of gas were undeveloped, all of which is attributable to Gunnison.
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:
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:
15. 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, 2001 (in thousands):
See Note 2 for a detailed discussion regarding the Company's accounting policy on the Revenue Allowance on Gross Amounts Billed. Approximately $1.8 million of such reserves at December 31, 2001 are related to the Enron Corporation bankruptcy.
16. 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,
CAL DIVE INTERNATIONAL, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 2001 and 2000.
17. SUBSEQUENT EVENTS
CANYON OFFSHORE, INC. ACQUISITION
In January 2002, CDI acquired approximately 85% of Canyon Offshore, Inc. (Canyon), a supplier of remotely operated vehicles (ROVs) and robotics to the offshore construction and telecommunications industries, in exchange for cash of $51 million, the assumption of $5 million of Canyon net debt and 181,000 shares of CDI common stock (143,000 shares of which were purchased by the Company during the fourth quarter of 2001). Cal Dive will purchase the remaining 15% at a price to be determined by Canyon's performance during the years 2002 through 2004, a portion of which could be compensation expense. The total purchase price is estimated to range from $66 million to $74 million. The acquisition will be accounted for as a purchase with the acquisition price being allocated to the assets acquired and liabilities assumed based upon their estimated fair values, with the excess being recorded as goodwill, which is initially estimated at approximately $40 million.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
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 2001 Annual Meeting of Shareholders. See also "Executive Officers of the Registrant" appearing in Part I of this Report.
ITEM 11.
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 2001 Annual Meeting of Shareholders.
ITEM 12.
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 2001 Annual Meeting of Shareholders.
ITEM 13.
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 2001 Annual Meeting of Shareholders.
PART IV
ITEM 14.
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, 2001.
Independent Auditors' Report. Consolidated Balance Sheets as of December 31, 2001 and 2000. Consolidated Statements of Operations for the Years Ended December 31, 2001, 2000 and 1999. Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2001, 2000 and 1999. Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999. 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.
November 1, 2000.
(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:
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* Filed herewith.
SIGNATURES
Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned. thereunto duly authorized.
CAL DIVE INTERNATIONAL, INC.
By: /s/ A. WADE PURSELL ------------------------------------ A. Wade Pursell Senior Vice President, Chief Financial Officer
March 27, 2002
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.
INDEX TO EXHIBITS
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* Filed herewith.