Item 1. BUSINESS
A. GENERAL
McDermott International, Inc. (“MII”), incorporated under the laws of the Republic of Panama in 1959, is an engineering and construction company with specialty manufacturing and service capabilities and is the parent company of the McDermott group of companies, which includes:
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J. Ray McDermott, S.A., a Panamanian subsidiary of MII (“JRMSA”), and its consolidated subsidiaries;
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McDermott Holdings, Inc., a Delaware subsidiary of MII (“MHI”), and its consolidated subsidiaries;
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McDermott Incorporated, a Delaware subsidiary of MHI (“MI”), and its consolidated subsidiaries;
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The Babcock & Wilcox Companies, a Delaware subsidiary of MI (“B&WC”);
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BWX Technologies, Inc., a Delaware subsidiary of B&WC (“BWXT”), and its consolidated subsidiaries; and
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The Babcock & Wilcox Company, a Delaware subsidiary of B&WC (“B&W”), and its consolidated subsidiaries.
In this Annual Report on Form 10-K, unless the context otherwise indicates, “we,” “us” and “our” mean MII and its consolidated subsidiaries.
We are a worldwide energy services company operating in three business segments:
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Offshore Oil and Gas Construction, previously referred to as Marine Construction Services, includes the results of operations of JRMSA and its subsidiaries and JRMH and its subsidiaries, hereafter collectively referred to as “JRM,” which supply services primarily to offshore oil and gas field developments worldwide. This segment’s principal activities include the front-end design and detailed engineering, fabrication and installation of offshore drilling and production facilities and installation of marine pipelines and subsea production systems. This segment operates in most major offshore oil and gas producing regions throughout the world, including the United States, Mexico, the Middle East, India, the Caspian Sea and Asia Pacific.
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Government Operations includes the results of operations of BWXT and its subsidiaries. This segment supplies nuclear components and provides various services to the U.S. Government, including uranium processing, environmental site restoration services and management and operating services for various U.S. Government-owned facilities, primarily within the nuclear weapons complex of the U.S. Department of Energy (“DOE”).
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Power Generation Systems includes the results of operations of B&W and its subsidiaries. This segment provides a variety of services, equipment and systems to generate steam and electric power at energy facilities worldwide. On February 22, 2006, B&W and three of its subsidiaries exited from Chapter 11 Bankruptcy proceedings. As a result of B&W’s Chapter 11 proceedings, we did not consolidate the results of operations of B&W and its subsidiaries in our consolidated financial statements from February 22, 2000 through February 22, 2006. Amounts reported for this segment during that period reflect only the results of operations of several foreign subsidiaries not owned by B&W. See Note 20 to our consolidated financial statements included in this report for information on B&W and its subsidiaries.
The following tables summarize our revenues and operating income by business segment for the years ended December 31, 2006, 2005 and 2004. See Note 17 to our consolidated financial statements included in this report for additional information about our business segments and operations in different geographic areas.
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See Note 17 to our consolidated financial statements included in this report for further information on unallocated corporate expenses.
B. OFFSHORE OIL AND GAS CONSTRUCTION
General
The Offshore Oil and Gas Construction segment’s business involves the front-end design and detailed engineering, fabrication and installation of offshore drilling and production facilities and installation of marine pipelines and subsea production systems. This segment also provides comprehensive project management and procurement services. This segment operates in most major offshore oil and gas producing regions throughout the world, including the United States, Mexico, the Middle East, India, the Caspian Sea and Asia Pacific.
Offshore Oil and Gas Construction Vessels and Properties
We operate a fleet of marine vessels used in major offshore construction. We currently own or, through our ownership interest in a joint venture, operate one derrick vessel and six combination derrick-pipelaying vessels. We also operate a pipelay vessel and a dive support vessel for a subdivision of the state-owned oil company of Azerbaijan. The lifting capacities of our derrick and combination derrick-pipelaying vessels range from 660 to 4,400 tons. These vessels range in length from 350 to 497 feet and are fully equipped with revolving cranes, auxiliary cranes, welding equipment, pile-driving hammers, anchor winches and a variety of additional equipment. Four of our owned and operated vessels are self-propelled, with three also having dynamic positioning systems. We also have a substantial inventory of specialized support equipment for intermediate water and deepwater construction and
pipelay. In addition, we own or lease a substantial number of other vessels, such as tugboats, utility boats, launch barges and cargo barges, to support the operations of our major marine construction vessels.
The following table sets forth certain information with respect to the major construction vessels utilized to conduct our Offshore Oil and Gas Construction business, including their location at December 31, 2006 (except where otherwise noted, each of the vessels is owned and operated by us):
Governmental regulations, our insurance policies and some of our financing arrangements require us to maintain our vessels in accordance with standards of seaworthiness and safety set by governmental authorities or classification societies. We maintain our fleet to the standards for seaworthiness, safety and health set by the American Bureau of Shipping, Den Norske Veritas and other world-recognized classification societies.
Our principal fabrication facilities are located near Morgan City, Louisiana, in Indonesia on Batam Island and in Dubai, U.A.E., and we are currently developing a new fabrication facility on the east coast of Mexico in the Port of Altamira, for which we are targeting to begin operations in the third quarter of 2007. We also operate a portion of the Baku Deepwater Jacket Factory fabrication facility in Baku, Azerbaijan, which is owned by a subsidiary of the State Oil Company of the Azerbaijan Republic. Our fabrication facilities are equipped with a wide variety of heavy-duty construction and fabrication equipment, including cranes, welding equipment, machine tools and robotic and other automated equipment. We fabricate a full range of offshore structures, from conventional jacket-type fixed platforms to intermediate water and deepwater platform configurations employing Spar, compliant-tower and tension leg technologies, as well as floating, production, storage and offtake (“FPSO”) technology.
Expiration dates, including renewal options, of leases covering land for JRM’s fabrication facilities at December 31, 2006 were as follows:
Morgan City, Louisiana
Years 2008-2048
Dubai (Jebel Ali), U.A.E.
Year 2015
Batam Island, Indonesia
Years 2029-2038
Altamira, Mexico
Year 2036
As a result of renewal options on the various tracts comprising the Morgan City fabrication facility, we have the ability, within our sole discretion, to continue leasing almost all the land we are currently using for that facility until 2048.
Foreign Operations
JRM’s revenues, net of intersegment revenues, and its segment income derived from operations located outside of the United States, as well as the approximate percentages to our total consolidated revenues and total consolidated segment income, respectively, for each of the last three years were as follows (dollars in thousands):
We participate in joint ventures involving operations in foreign countries that sometimes require majority ownership by local interests. See Note 17 to our consolidated financial statements included in this report for further information on the geographic distribution of our revenues.
Customers
JRM’s customers are primarily oil and gas companies, including several foreign government-owned companies. JRM’s five largest customers during 2006 were Azerbaijan International Operating Company, Aramco Overseas Company BV, Dolphin Energy Limited, Ras Laffan Liquified Natural Gas Company Limited and Conoco Indonesia, Inc., which accounted for 8.5%, 6.6%, 3.1%, 1.9% and 1.3% of our total consolidated revenues, respectively. JRM’s five largest customers during 2005 were Azerbaijan International Operating Company, Ras Laffan Liquified Natural Gas Company Limited, BP Plc and its subsidiaries, Exxon Neftegas Limited and Apache Energy Limited, which accounted for 20.0%, 5.8%, 5.3%, 4.9% and 4.5% of our total consolidated revenues, respectively.
The level of engineering and construction services required by any one customer depends upon the amount of that customer’s capital expenditure budget for offshore construction services in any single year. Consequently, customers that account for a significant portion of revenues in one year may represent an immaterial portion of revenues in subsequent years.
Contracts
We have historically performed work on a fixed-price, cost-plus or day-rate basis or a combination of these methods. Most of our long-term contracts have provisions for progress payments. We attempt to cover anticipated increases in costs of labor, material and service costs of our long-term contracts, either through an estimate of such charges, which is reflected in the original price, or through price escalation clauses.
We recognize our contract revenues and related costs on a percentage-of-completion basis. Accordingly, we review contract price and cost estimates periodically as the work progresses and reflect adjustments in income proportionate to the percentage of completion in the period when we revise those estimates. To the extent that these adjustments result in a reduction or an elimination of previously reported profits with respect to a project, we would recognize a charge against current earnings, which could be material.
Our arrangements with customers frequently require us to provide letters of credit or bid and performance bonds to secure bids or performance under contracts for offshore construction services. While these letters of credit and bonds may involve significant dollar amounts, historically, there have been no material payments to our customers under these arrangements. These arrangements are typical in the industry for projects outside the U.S. Gulf of Mexico.
In the event of a contract deferral or cancellation, we are generally entitled to recover costs incurred, settlement expenses and profit on work completed prior to deferral or termination. While we have not generally experienced significant project cancellations, significant or numerous cancellations could adversely affect our business, financial condition and results of operations.
Backlog
As of December 31, 2006 and 2005, our Offshore Oil and Gas Construction segment’s backlog amounted to approximately $4.1 billion and $1.8 billion, respectively. This represents approximately 54% and 50% of our total consolidated backlog at December 31, 2006 and 2005, respectively. Of our December 31, 2006 backlog in this segment, we expect to recognize revenues as follows (in approximate millions):
While fabrication projects are typically awarded substantially in advance of performance as a result of the required lead time for procurement, the offshore construction industry is highly seasonal in some geographic regions. Because of the more conducive weather conditions, most installation operations are conducted in the warmer months of the year in those areas, and many of these contracts are awarded with only a short period of time before the desired time of project performance. Projects in our backlog may be cancelled by customers.
Raw Materials
Our Offshore Oil and Gas Construction segment uses raw materials, such as carbon and alloy steels in various forms, welding gases, paint, fuels and lubricants, which are available from many sources. We generally purchase these raw materials and components as needed for individual contracts. Although shortages of some raw materials and fuels have existed from time to time, no serious shortage exists at the present time. Our Offshore Oil and Gas Construction segment does not depend on a single source of supply for any significant raw materials.
Competition
We believe we are among the few offshore construction contractors capable of providing a full range of services in major offshore oil and gas producing regions of the world. We believe that the substantial capital costs involved in becoming a full-service offshore construction contractor create a significant barrier to entry into the market as a global, fully integrated competitor. We do, however, face substantial competition from regional competitors and less integrated providers of offshore construction services, such as engineering firms, fabrication facilities, pipelaying companies and shipbuilders.
A number of companies compete with us in each of the separate marine pipelay and construction and fabrication phases in various parts of the world. These competitors include Allseas Marine Contractors S.A.; Daewoo Engineering & Construction Co., Ltd.; Global Industries, Ltd.; NPCC (Abu Dhabi); Heerema Group;
Hyundai Heavy Industrial Co., Ltd.; Kiewit Offshore Services, Ltd.; Nippon Steel Corporation; Saipem S.p.A.; Acergy S.A.; and Technip S.A. Contracts are usually awarded on a competitive bid basis. Although we believe customers consider, among other things, the availability and technical capabilities of equipment and personnel, efficiency, condition of equipment, safety record and reputation, price competition is normally the primary factor in determining which qualified contractor with available equipment is awarded a contract. Major construction vessels have few alternative uses and, because of their nature and the environment in which they work, have relatively high maintenance costs whether or not they are operating. See the discussion in Item 1A, “Risk Factors,” for additional information on the competitive nature of our Offshore Oil and Gas Construction segment.
Factors Affecting Demand
Our Offshore Oil and Gas Construction segment’s activity depends mainly on the capital expenditures for offshore construction services of oil and gas companies and foreign governments for construction of development projects. Numerous factors influence these expenditures, including:
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oil and gas prices, along with expectations about future prices;
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the cost of exploring for, producing and delivering oil and gas;
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the terms and conditions of offshore leases;
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the discovery rates of new oil and gas reserves in offshore areas;
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the ability of businesses in the oil and gas industry to raise capital; and
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local and international political and economic conditions.
See Item 1A, “Risk Factors,” for further information on factors affecting demand.
C. GOVERNMENT OPERATIONS
General
Our Government Operations segment consists of the operations of BWXT and its subsidiaries. Through this segment, we manage complex, high-consequence nuclear and national security operations, and we are a principal supplier of nuclear components and advanced energy products to the U.S. Government. Through our operation of this segment, we have over 50 years of experience in the ownership and operation of large nuclear development, production and reactor facilities, including 48 years of providing precision-manufactured components for the U.S. Navy. Principal areas of operation include:
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providing precision manufactured components for the U.S. Navy’s nuclear vessels;
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managing and operating nuclear production facilities;
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managing and operating environmental management sites;
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managing spent nuclear fuel and transuranic waste for the DOE;
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providing critical skills and resources for DOE sites; and
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developing and deploying next generation technology in support of U.S. Government programs.
BWXT conducts the operations of our Government Operations segment through two primary subsidiaries or divisions: BWXT Services, Inc. and its Nuclear Operations Division.
In 2006, BWXT formed its Nuclear Operations Division by consolidating its Nuclear Equipment Division and its Nuclear Products Division. We believe this consolidation will result in greater operating efficiencies, cost savings and synergies in BWXT’s nuclear business.
Properties
BWXT’s principal manufacturing facilities are located in:
Each of these facilities is located on property we own.
The Lynchburg, Virginia facility, which is BWXT’s Nuclear Operations Division’s primary manufacturing plant, is the nation’s largest commercial high-enriched uranium processing facility. The facility resides on 437 acres with 870,000 square feet of manufacturing area and comprises approximately 60 buildings and trailers. The site is the recipient of the highest rating given by the Nuclear Regulatory Commission for license performance. The performance review determines the safe and secure conduct of operations of the facility. The site is also the largest commercial International Atomic Energy Agency-certified facility in the U.S.
Precision components and products ranging in size from a few grams to hundreds of tons can be accommodated in the Lynchburg facility. Modern multi-axis machining centers use computer controls with direct links to distributed computer-aided design and manufacturing networks. Computer-controlled electron beam, plasma and tungsten inert gas welding are used for joining a variety of special materials, including nuclear, refractory, superconducting alloys, stainless steel, inconel, titanium and aluminum. Other facility capabilities include:
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advanced heat treatment to optimize material properties of components;
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computerized real-time accept/reject dimensional inspection coordinate measuring systems for dimensional inspection, custom inspection gauging and calibration, destructive/nondestructive testing, dye check, Zyglo inspection, Cryogenic testing, ultrasonic inspection, magnetic particle inspection and computer or direct numerical control machining and inspection;
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the design and development of advanced nuclear fuels systems for space, defense, research and commercial applications; and
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the production of aluminum-clad uranium fuel elements of high and low enrichments for research and test reactors.
The other manufacturing facilities for BWXT’s Nuclear Operations Division are the Barberton, Ohio and Mount Vernon, Indiana facilities. The Barberton facility includes 69 acres with 548,000 square feet of manufacturing area and 119,000 square feet of office area. The Mount Vernon facility, located on the Ohio River, includes 580,000 square feet of manufacturing space and 61,000 square feet of office space. The main manufacturing bay of the Mount Vernon facility is serviced by two 500-ton cranes, which extend over a barge dock on the Ohio River.
Both the Barberton and Mount Vernon facilities utilize multiple, full-contouring, computer numerical control horizontal and vertical machining centers; large gantry robotic welding centers; and state-of-the-art support equipment for machining and welding.
Operations
BWXT manages and operates complex, high-consequence nuclear and national security operations for the DOE and the National Nuclear Security Administration (“NNSA”), primarily through joint ventures, limited liability corporations and partnerships. In addition, BWXT provides a broad array of technical services in support of DOE and NNSA operations and facilities.
BWXT provides operations, management and technical services in support of the following U.S. Government facilities:
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Idaho National Laboratory. The Idaho National Laboratory is an 890-square-mile DOE site near Idaho Falls, Idaho that serves nuclear, national security and scientific research purposes. Operations at the facility include processing and managing radioactive and hazardous materials and nuclear reactor design, demonstration and safety. BWXT manages the nuclear and national security operations of this site as a team member of the Battelle Energy Alliance, the operator of the site.
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Savannah River Site. The Savannah River Site is a 310-square mile DOE industrial complex, located in Aiken, South Carolina, dedicated to the processing and storing of nuclear materials in support of the national defense and U.S. nuclear nonproliferation efforts. The site also develops and deploys technologies to improve the environment and treat nuclear and hazardous wastes. As an integrated contractor at this site, BWXT is responsible for nuclear materials management and the startup and operation of a facility to extract tritium, a radioactive form of hydrogen necessary for the nation’s nuclear weapons stockpile.
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Strategic Petroleum Reserve. The Strategic Petroleum Reserve provides emergency supply of crude oil stored at four sites in huge underground salt caverns along the Texas and Louisiana Gulf Coast. Since 1993, the facility has been managed and operated by DynMcDermott Petroleum Operations Company, a joint venture of DynCorp/CSC, McDermott International, Inc., International Matex Tank and Terminals and Jacobs Engineering. BWXT manages the contract for McDermott International, Inc.
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Pantex Plant. The Pantex Plant is a 16,000-acre NNSA site located near Amarillo, Texas. Key operations at this facility include evaluating, retrofitting and repairing nuclear weapons; dismantling and sanitizing nuclear weapons components; developing, testing and fabricating high-explosive components; and handling and storing plutonium pits. BWXT, through a joint venture with Honeywell International Inc. and Bechtel National, Inc., manages and operates the facility.
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Y-12 National Security Complex. The Y-12 facility is an 811-acre NNSA site located in Oak Ridge, Tennessee. Operations at the site focus on the production, refurbishment and dismantlement of nuclear weapons components, storage of nuclear material and the prevention of the proliferation of weapons of mass destruction. As the prime contractor, BWXT, through a joint venture with Bechtel National, Inc., manages the facility.
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Los Alamos National Laboratory. The Los Alamos National Laboratory is located in New Mexico and is the DOE weapons laboratory with the largest number of defense facilities and weapons-related activities. It is the foremost site for the government’s ongoing research and development on the measures necessary for certifying the safety and reliability of nuclear weapons without the use of nuclear testing. Since 2006, BWXT, as part of Los Alamos National Security, LLC, is the management and operations contractor for this facility. Previously, BWXT was a subcontractor to the University of California at this facility, providing Nuclear Facility Operations Assessment, Advisory and Technical Support Services.
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Oak Ridge National Laboratory. The Oak Ridge National Laboratory is a multi-disciplined science and technology complex located on a 58-square mile site near Oak Ridge, Tennessee. This facility is managed and operated by UT-Battelle, LLC for the DOE. BWXT, as an integrated subcontractor to UT-Battelle, LLC, provides technical support in the areas of nuclear facility management and operation.
With manufacturing facilities located in Barberton, Ohio, Mount Vernon, Indiana, and Lynchburg, Virginia, BWXT’s Nuclear Operations Division specializes in the design and manufacture of close-tolerance and high-quality equipment for nuclear applications. In addition, it is a leading manufacturer of critical nuclear components, fuels and assemblies for government and commercial uses. The division has supplied nuclear components for DOE programs since the 1950s. In addition, it is the largest domestic supplier of research reactor fuel elements for colleges, universities and national laboratories. BWXT’s Nuclear Operations Division also provides uranium targets used for medical isotopes and converts or downblends high-enriched uranium into low-enriched fuel for use in commercial reactors to generate electricity. The division also has over 100 years of experience in supplying heavy fabrications for industrial use, including components for defense applications.
BWXT’s Nuclear Operations Division works closely with the DOE supported non-proliferation program. Currently, it is assisting in the development of a high-density, low-enriched uranium fuel required for high-enriched uranium test reactor conversions. In addition, this division has been a leader in the receipt, storage, characterization, dissolution, recovery and purification of a variety of uranium-bearing materials. All phases of uranium downblending and uranium recovery are provided at the division’s Lynchburg, Virginia site.
BWXT’s Nuclear Operations Division has an experienced staff of design and manufacturing engineers capable of performing full scope, prototype design work coupled with manufacturing integration. Its engineering capabilities include:
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steam separation equipment design and development;
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thermal-hydraulic design of reactor plant components;
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structural component design for precision manufacturing;
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materials expertise in high-strength, low-alloy steels, nickel-based materials and others;
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material procurement of tubing, forgings, weld wire; and
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fully-equipped metallographic and chemical analysis laboratory facility.
The Nuclear Operations Division also implements strong quality assurance programs for its products.
Customers
The U.S. Government is the primary customer of our Government Operations segment, comprising 97% of segment revenues for the year ended December 31, 2006 and 94% of segment revenues for the year ended December 31, 2005.
The U.S. Government accounted for approximately 15%, 31%, and 27% of our total consolidated revenues for the years ended December 31, 2006, 2005, and 2004, respectively, including 14%, 28%, and 26%, respectively, related to nuclear components.
Contracts
Our contracts with the federal government are subject to annual funding determinations. In addition, contracts with the federal government and its prime contractors usually contain standard provisions for termination at the convenience of the government or the prime contractor. Upon termination of such a contract, we are generally entitled to recover costs incurred, settlement expenses and profit on work completed prior to termination. While we have not generally experienced significant project cancellations, significant or numerous cancellations could adversely affect our business, financial condition and results of operations.
The contracts for the management and operation of U.S. Government facilities are generally structured as five-year contracts with five-year renewal options, which are exercisable by the customer. These are cost-reimbursement contracts with a U.S. Government credit line with little corporate-funded working capital. As a U.S. Government contractor, we are subject to federal regulations under which our right to receive future awards of new federal contracts may be unilaterally suspended or barred if we are convicted of a crime or indicted based on allegations of a violation of specific federal statutes.
Backlog
As of December 31, 2006 and 2005, our Government Operations segment’s backlog amounted to approximately $1.3 billion and $1.8 billion, or approximately 17% and 50%, respectively, of our total consolidated backlog. Of our December 31, 2006 backlog in this segment, we expect to recognize revenues as follows (in approximate millions):
As of December 31, 2006, this segment’s backlog with the U.S. Government was $1.3 billion (of which $25.1 million had not yet been funded), or approximately 15% of our total consolidated backlog. During the year ended December 31, 2006, the U.S. Government awarded new orders of approximately $94.3 million to this segment. Historically, this segment received a substantial amount of its backlog from the U.S. Government in the fourth quarter of each year. We are currently negotiating terms and conditions on potential new bookings with the U.S. Government and expect to receive awards in the first quarter of 2007, in line with prior years’ fourth quarter amounts.
Raw Materials
Our Government Operations segment relies on several single-source suppliers for materials used in its products. We believe these suppliers are viable, and we and the U.S. Government expend significant effort to maintain the supplier base.
Competition
Our Government Operations segment is engaged in a highly competitive business, through its management and operation of U.S. Government facilities, in which customer contracts are typically awarded through competitive bidding processes. We compete with other general and specialty contractors, primarily on price, reputation, value and quality of service. Our Government Operations segment’s competitors in the delivery of goods and services to the U.S. Government and the operation of U.S. Government facilities include Bechtel National, Inc., Washington Group International, CH2M Hill, Inc., Fluor Corporation, Lockheed Martin Corporation and Nuclear Fuel Services, Inc.
Factors Affecting Demand
Our Government Operations segment’s operations are generally capital-intensive on the manufacturing side. This segment may be impacted by U.S. Government budget restraints and delays.
The demand for nuclear components for the U.S. Government comprises a substantial portion of this segment’s backlog. We expect that orders for nuclear components will continue to be a significant part of backlog for the foreseeable future; however, such orders are subject to defense department budget constraints.
See Section 1A, “Risk Factors,” for further information on factors affecting demand.
D. POWER GENERATION SYSTEMS
General
Our Power Generation Systems segment consists primarily of the operations of B&W, which were not consolidated in our financial results from February 22, 2000 through February 22, 2006. See Note 20 to our consolidated financial statements included in this report for information on the reconsolidation of B&W, effective February 22, 2006.
B&W is a leading supplier of fossil fuel-fired steam generating systems, large replacement commercial nuclear steam generators and components, environmental equipment and components and related services to customers around the world. It designs, engineers, manufactures, constructs and services large utility and industrial power generation systems, including boilers used to generate steam in electric power plants, pulp and paper making, chemical and process applications and other industrial uses.
Properties
B&W’s headquarters are located in Barberton, Ohio.
B&W’s principal manufacturing facilities are located in:
B&W owns each of these facilities.
B&W’s facility in West Point, Mississippi specializes in the fabrication of products used in the power generation
industry, including furnace wall panels, complete cyclone furnace assemblies, longflow economizers and generating banks, heat recovery steam generators, package boilers and related mechanical and structural components. In addition, the products fabricated at this facility serve the electric utility, pulp and paper, and other industries.
The Lancaster, Ohio facility is the headquarters of Diamond Power International, Inc. (“DPII”), a wholly owned subsidiary of B&W. DPII is the largest supplier of boiler-cleaning equipment in the world. This facility supplies cleaning systems for heat transfer surfaces in boilers of all sizes and for the burning of all fossil fuels.
B&W’s Cambridge, Ontario, Canada facility specializes in the production of steam generation products and services for nuclear utilities, as well as Canadian fossil fuel utility and industrial markets. The Cambridge facility encompasses approximately 520,780 square feet of office and manufacturing space with plate, machine, header, tube and boiler shops. In addition, the Cambridge facility contains a 37,000 square foot nuclear assembly clean room built specifically for the assembly of nuclear steam generators. The Cambridge facility houses a modern welding and Industrial Skills Training Service Center, a licensed private career college and testing center.
The Melville, Saskatchewan, Canada facility produces steam generation products and custom engineering services for the Canadian fossil fuel utilities and industrial markets in western Canada and the U.S. This plant fabricates boiler components, including pressure parts, heater elements, economizer tube elements, hoppers and ducts.
B&W’s Esbjerg, Denmark facility is the principal facility of Babcock & Wilcox Volund. This facility is equipped with a wide variety of heavy-duty fabrication equipment, including welding equipment, machine tools and other automated equipment. The primary focus of this facility is on new plant equipment for waste-to-energy plants.
The Jingshan, Hubei, China facility is a leading supplier of boiler cleaning equipment to China’s utility power market. In addition, it is also a supplier of ash handling products and systems for domestic and export markets.
In addition to the above, B&W has several smaller facilities in different locations around the world. It also has a significant boiler manufacturing joint venture in China.
Operations
B&W and its subsidiaries:
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provide engineered-to-order services, products and systems for energy conversion worldwide and related auxiliary equipment, such as burners, pulverizer mills, soot blowers and ash handlers;
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manufacture heavy-pressure equipment for energy conversion, such as boilers fueled by coal, oil, bitumen, natural gas, solid municipal waste, biomass and other fuels;
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fabricate steam generators and reactor heads for nuclear power plants;
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design and supply environmental control systems, including both wet and dry scrubbers for flue gas desulfurization, modules for selective catalytic reduction of nitrous oxides and electrostatic precipitators and similar devices;
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construct power plant equipment and provide related heavy mechanical erection services;
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support operating plants with a wide variety of services, including the installation of new systems and replacement parts, engineered upgrades, construction, maintenance and field technical services, such as condition assessments;
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provide inventory services to help customers respond quickly to plant interruptions and construction crews to assist in maintaining and repairing operating equipment; and
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provide power through cogeneration, refuse-fueled power plants and other independent power-producing facilities and participate in this market as contractors for engineer-procure-construct services, as equipment suppliers, as operations and maintenance contractors and as an owner.
B&W’s revenues, net of intersegment revenues, and its segment income derived from operations located outside of the United States, as well as the approximate percentages to our total consolidated revenues and total consolidated
segment income, respectively, for the year ended December 31, 2006 were as follows (dollars in thousands):
Customers
Our Power Generation Systems segment’s principal customers are government- and investor-owned utilities and independent power producers, businesses in various process industries, such as pulp and paper mills, petrochemical plants, oil refineries and steel mills and other steam-using businesses and governmental units. Customers normally purchase services, equipment or systems from B&W after an extensive evaluation process based on competitive bids.
B&W’s five largest customers during the year ended December 31, 2006 were American Electric Power Company, Inc., Duke Energy Corporation, Bechtel Power Group Incorporated, Bruce Power Limited and First Energy Corporation, which accounted for 5.3%, 4.0%, 2.7%, 2.6% and 1.5% of our total consolidated revenues, respectively.
Contracts
We have historically performed work on a fixed-price or cost-plus basis or a combination of these methods. Most of our long-term contracts have provisions for progress payments. We attempt to cover anticipated increases in costs of labor, material and service costs of our long-term contracts, either through an estimate of such charges, which is reflected in the original price, or through price escalation clauses. Most of those long-term contracts contain provisions for progress payments.
We generally recognize our contract revenues and related costs on a percentage-of-completion basis. Accordingly, we review contract price and cost estimates periodically as the work progresses and reflect adjustments in income proportionate to the percentage of completion in the period when we revise those estimates. To the extent that these adjustments result in a reduction or an elimination of previously reported profits with respect to a project, we would recognize a charge against current earnings, which could be material.
Our arrangements with customers frequently require us to provide letters of credit or bid and performance bonds to secure bids or performance under contracts. While these letters of credit and bonds may involve significant dollar amounts, historically, there have been no material payments to our customers under these arrangements.
In the event of a contract deferral or cancellation, we are generally entitled to recover costs incurred, settlement expenses and profit on work completed prior to deferral or termination. Significant or numerous contract cancellations could adversely affect our business, financial condition and results of operations.
Backlog
As of December 31, 2006, our Power Generation Systems segment’s consolidated backlog amounted to approximately $2.2 billion, or approximately 29% of our total consolidated backlog. At December 31, 2005, B&W’s consolidated backlog amounted to approximately $2.1 billion, which was not included in our total consolidated backlog due to B&W’s then pending Chapter 11 proceedings. Of the December 31, 2006 backlog in our Power Generation Systems segment, we expect to recognize revenues as follows (in approximate millions):
In June 2006, B&W was awarded separate contracts to supply eight supercritical, coal-fired boilers and selective catalytic reduction (“SCR”) systems as part of TXU Corp.’s solid-fuel power generation program in Texas. The expected revenues from these awards exceeded $1 billion. B&W’s backlog at June 30, 2006 and September 30, 2006 reflected all the TXU awards. B&W has received notice from TXU to suspend activity on five of the eight boilers and SCR systems. The notifications did not specify the length of the suspensions. The notifications obligate B&W to suspend performance on these five units. The suspension provisions allow B&W reimbursement of suspension cost and equitable adjustment to the price, schedule and other relevant terms of the contract. Additionally, on February 26, 2007, TXU issued a press release and conducted an investor conference call relating to a proposed buyout transaction involving TXU announced on that date. In the investor conference call, representatives of TXU indicated that it is reducing planned coal-fueled generation units in Texas from eleven to three and that the permitting process for the eight units to be provided by B&W will be suspended. Because we have received no cancellation notices from TXU, we have continued to work on the three remaining units which were not suspended; however, we have excluded the TXU award for the eight units from our ending backlog at December 31, 2006.
Raw Materials
Our Power Generation Systems segment uses raw materials, such as carbon and alloy steels in various forms, including plates, forgings, structurals, bars, sheets, strips, heavy wall pipes and tubes. We also purchase many components and accessories for assembly. We generally purchase these raw materials and components as needed for individual contracts. Although shortages of some raw materials have existed from time to time, no serious shortage exists at the present time. Our Power Generation Systems segment does not depend on a single source of supply for any significant raw materials.
Competition
B&W primarily competes with:
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a number of domestic and foreign-based companies specializing in steam-generating systems, equipment and services, including Alstom S.A., Mitsui Babcock Energy Limited, Babcock Power, Foster Wheeler Corporation, Mitsubishi Heavy Industries and Hitachi, Ltd.;
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a number of additional companies in the markets for environmental control equipment and related specialized industrial equipment and in the independent power-producing business; and
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other suppliers of replacement parts, repair and alteration services and other services required to backfit and maintain existing steam systems.
Factors Affecting Demand
Our Power Generation Systems segment’s overall activity depends mainly on the capital expenditures of electric power generating companies and other steam-using industries. Several factors influence these expenditures, including:
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prices for electricity, along with the cost of production and distribution;
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prices for coal and natural gas and other sources used to produce electricity;
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demand for electricity, paper and other end products of steam-generating facilities;
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availability of other sources of electricity, paper or other end products;
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requirements for environmental improvements;
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level of capacity utilization at operating power plants, paper mills and other steam-using facilities;
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requirements for maintenance and upkeep at operating power plants and paper mills to combat the accumulated effects of wear and tear;
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ability of electric generating companies and other steam users to raise capital; and
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relative prices of fuels used in boilers, compared to prices for fuels used in gas turbines and other alternative forms of generation.
Our Power Generation Systems segment’s products and services are capital intensive. As such, customer demand is heavily affected by the variations in customer’s business cycles and by the overall economies of the countries in which they operate.
See Section 1A, “Risk Factors,” for further information on factors affecting demand.
E. PATENTS AND LICENSES
We currently hold a large number of U.S. and foreign patents and have numerous patent applications pending. We have acquired patents and licenses and granted licenses to others when we have considered it advantageous for us to do so. Although in the aggregate our patents and licenses are important to us, we do not regard any single patent or license or group of related patents or licenses as critical or essential to our business as a whole. In general, we depend on our technological capabilities and the application of know-how, rather than patents and licenses, in the conduct of our various businesses.
F. RESEARCH AND DEVELOPMENT ACTIVITIES
We conduct our principal research and development activities through individual business units at our various manufacturing plants and engineering and design offices. Our research and development activities cost approximately $45.2 million, $34.1 million and $29.7 million in the years ended December 31, 2006, 2005 and 2004, respectively. Contractual arrangements for customer-sponsored research and development can vary on a case-by-case basis and include contracts, cooperative agreements and grants. Of our total research and development expenses, our customers paid for approximately $26.5 million, $30.8 million and $25.1 million in the years ended December 31, 2006, 2005 and 2004, respectively.
G. INSURANCE
We maintain liability and property insurance in amounts we consider adequate for those risks we consider appropriate to insure. Some risks are not insurable or insurance to cover them is available only at rates that we consider uneconomical. These risks include war and confiscation of property in some areas of the world, pollution liability, business interruption, asbestos liability and other liabilities related to occupational health exposures. Depending on competitive conditions and other factors, we endeavor to obtain contractual protection against some uninsured risks from our customers. Insurance or contractual indemnity protection, when obtained, may not be sufficient or effective under all circumstances or against all hazards to which we may be subject.
Coverage to insure against liability and property damage losses resulting from nuclear accidents at reactor facilities of our utility customers is not available in the commercial insurance marketplace, but we do have some protection against claims based on such losses. To protect against liability for damage to a customer’s property, we endeavor to obtain waivers of subrogation from the customer and its insurer and are usually named as an additional insured under the utility customer’s nuclear property policy. We also attempt to cap our overall liability in our contracts. To protect against liability from claims brought by third parties, we are insured under the utility customer’s nuclear liability policies and have the benefit of the indemnity and limitation of any applicable liability provision of the Price-Anderson Act. The Price-Anderson Act limits the public liability of manufacturers and operators of licensed nuclear facilities and other parties who may be liable in respect of, and indemnifies them against, all claims in excess of a certain amount. This amount is determined by the sum of commercially available liability insurance plus certain retrospective premium assessments payable by operators of commercial nuclear reactors. For those sites where we provide environmental remediation services, we seek the same protection from our customers as we do for our other nuclear activities. The Price-Anderson Act, as amended, includes a sunset provision and requires renewal each time that it expires. Contracts that were entered into during a period of time that Price-Anderson was in full force and effect continue to receive the benefit of the Price-Anderson Act’s nuclear indemnity. The Price-Anderson Act was set to expire on December 31,
2006; however, Congress re-enacted and extended the Price-Anderson Act in 2005 for 20 years through December 31, 2025. BWXT currently has no contracts involving nuclear materials that are not covered by and subject to the nuclear indemnity provisions of the Price-Anderson Act.
Although we do not own or operate any nuclear reactors, we have coverage under commercially available nuclear liability and property insurance for two of our three locations that are licensed to possess special nuclear materials. Of the three locations, two are located at our Lynchburg, Virginia site. These facilities are insured under a nuclear liability policy that also insures the facility of Framatome Cogema Fuel Company (“FCFC”), formerly B&W Fuel Company, which we sold during the fiscal year ended March 31, 1993. The two licensed facilities share the same nuclear liability insurance limit, as the commercial insurer would not allow FCFC to obtain a separate nuclear liability insurance policy. Due to the type or quantity of nuclear material present under contract with the U.S. Government, the two facilities in Lynchburg have statutory indemnity and limitation of liability under the Price-Anderson Act. In addition, our contracts to manufacture and supply nuclear components to the U.S. Government contain statutory indemnity clauses under which the U.S. Government has assumed the risks of public liability claims related to nuclear incidents.
BWXT, through two of its dedicated limited liability companies, has management and operating agreements with the U.S. Government for the Pantex and Y-12 facilities. Most insurable liabilities arising from these sites are not protected in our corporate insurance program but rely on government contractual agreements and certain specialized self-insurance programs funded by the U.S. Government. The U.S. Government has historically fulfilled its contractual agreement to reimburse for insurable claims, and we expect it to continue this process during our administration of these two facilities. However, in most of these situations in which the U. S. Government is contractually obligated to pay, the payment obligation is subject to the availability of authorized government funds.
B&W, principally through its manufacture of heavy-pressure equipment for energy conversion, such as boilers, and its fabrication of nuclear steam generators, is subject to risks such as accidents resulting in the loss of life or property and potential environmental issues. While we attempt to obtain adequate insurance to cover these risks, it is possible that insurance against these risks might be unavailable or available only at rates we consider uneconomical. See Note 10 to our consolidated financial statements included in this report for additional information.
JRM’s offshore construction business is subject to the usual risks of operations at sea, including accidents resulting in the loss of life or property, pollution or other environmental mishaps, adverse weather conditions, mechanical failures, collisions, property losses to our vessels, business interruption due to damage to the equipment or political action in foreign countries and labor stoppages. JRM has additional exposure because it uses expensive construction equipment, sometimes under extreme weather conditions, often in remote areas of the world. In many cases, JRM also operates on or in proximity to existing offshore facilities. These facilities are subject to damage that could result in the escape of oil and gas into the sea. Litigation arising from any such event may result in our being named as a defendant in lawsuits asserting large claims. Depending on competitive conditions and other factors, we have endeavored to obtain contractual protection against uninsured risks from our customers. When obtained, such contractual indemnification protection may not in all cases be supported by adequate insurance maintained by the customer. These contractual protections are not available in many cases. In addition, in recent years, we have been named as a defendant in litigation concerning exposure to lead-based paint, silica, asbestos and welding rod fumes. While we are vigorously defending these claims, it is possible that existing insurance will not be sufficient to cover all potential exposure should these proceedings result in an adverse decision for us. See Note 10 to our consolidated financial statements included in this report for additional information on these issues.
We have several wholly owned insurance subsidiaries that provide workers compensation, employer’s liability, general and automotive liability insurance and, from time to time, builder’s risk within certain limits, marine hull and workers’ compensation insurance to our companies. We may also have business reasons in the future to have these insurance subsidiaries accept other risks which we cannot or do not wish to transfer to outside insurance companies. These insurance subsidiaries have not provided significant amounts of insurance to unrelated parties. Claims as a result of our operations could adversely impact the ability of these captive insurers to respond to all claims presented, although we believe such a result is unlikely.
Additionally, upon the February 22, 2006 effectiveness of the settlement of the Chapter 11 proceedings of B&W and its affiliated debtor subsidiaries, MII and most of its subsidiaries contributed substantial insurance rights to the asbestos personal injury trust, including rights to (1) certain B&W pre-1979 primary and excess insurance
coverages and (2) certain 1979-1986 excess insurance coverage of MII and its affiliates, including JRM, MHI, BWXT and B&W, which 1979-1986 excess policies had an aggregate face value of available limits of coverage of approximately $1.15 billion. These insurance rights provided cover for, among other things, asbestos and other personal injury claims, subject to the terms and conditions of the policies. With the contribution of these insurance rights to the asbestos personal injury trust, MII and its affiliates, including JRM, MHI, BWXT and B&W, may have underinsured or uninsured exposure for non-B&W-derivative asbestos claims or other personal injury or other claims that would have been insured under these coverages had the insurance rights not been contributed to the asbestos personal injury trust.
H. EMPLOYEES
At December 31, 2006, we employed approximately 27,800 persons, including employees of B&W, which was not consolidated at December 31, 2005, compared with 14,200 at December 31, 2005. Approximately 11,100 of our employees were members of labor unions at December 31, 2006, compared with approximately 3,100 at December 31, 2005. The increase in employees that are members of labor unions was primarily attributable to an increase in labor workforce for JRM and the reconsolidation of B&W. Many of our operations are subject to union contracts, which we customarily renew periodically. Currently, we consider our relationships with our employees to be satisfactory.
I. GOVERNMENTAL REGULATIONS AND ENVIRONMENTAL MATTERS
General
Many aspects of our operations and properties are affected by political developments and are subject to both domestic and foreign governmental regulations, including those relating to:
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construction and equipping of offshore production platforms and other offshore facilities;
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construction and equipping of electric power and other industrial facilities;
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possessing and processing special nuclear materials;
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marine vessel safety;
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workplace health and safety;
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currency conversions and repatriation;
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taxation of foreign earnings and earnings of expatriate personnel; and
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protecting the environment.
In addition, we depend on the demand for our offshore construction services from the oil and gas industry and, therefore, are affected by changing taxes, price controls and other laws and regulations relating to the oil and gas industry generally. The adoption of laws and regulations curtailing offshore exploration and development drilling for oil and gas for economic and other policy reasons would adversely affect our operations by limiting demand for our services.
We are required by various other governmental and quasi-governmental agencies to obtain certain permits, licenses and certificates with respect to our operations. The kinds of permits, licenses and certificates required in our operations depend upon a number of factors.
The exploration and development of oil and gas properties on the continental shelf of the United States is regulated primarily under the U.S. Outer Continental Shelf Lands Act and related regulations. These laws require the construction, operation and removal of offshore production facilities located on the outer continental shelf of the United States to meet stringent engineering and construction specifications. Similar regulations govern the plugging and abandoning of wells located on the outer continental shelf of the United States and the removal of all production facilities. Violations of regulations issued pursuant to the U.S. Outer Continental Shelf Lands Act and related laws can result in substantial civil and criminal penalties, as well as injunctions curtailing operations.
We cannot determine the extent to which new legislation, new regulations or changes in existing laws or regulations may affect our future operations.
Environmental
Our operations and properties are subject to a wide variety of increasingly complex and stringent foreign, federal, state and local environmental laws and regulations, including those governing discharges into the air and water, the handling and disposal of solid and hazardous wastes, the remediation of soil and groundwater contaminated by hazardous substances and the health and safety of employees. Sanctions for noncompliance may include revocation of permits, corrective action orders, administrative or civil penalties and criminal prosecution. Some environmental laws provide for strict, joint and several liability for remediation of spills and other releases of hazardous substances, as well as damage to natural resources. In addition, companies may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. Such laws and regulations may also expose us to liability for the conduct of or conditions caused by others or for our acts that were in compliance with all applicable laws at the time such acts were performed.
These laws and regulations include the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (“CERCLA”), the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act and similar laws that provide for responses to, and liability for, releases of hazardous substances into the environment. These laws and regulations also include similar foreign, state or local counterparts to these federal laws, which regulate air emissions, water discharges, hazardous substances and waste and require public disclosure related to the use of various hazardous substances. Our operations are also governed by laws and regulations relating to workplace safety and worker health, primarily, in the United States, the Occupational Safety and Health Act and regulations promulgated thereunder.
We are currently in the process of investigating and remediating some of our former operating sites. Although we have recorded reserves in connection with certain of these matters, due to the uncertainties associated with environmental remediation, we cannot assure you that the actual costs resulting from these remediation matters will not exceed the recorded reserves.
Our compliance with U.S. federal, state and local environmental control and protection regulations resulted in pretax charges of approximately $11.8 million in the year ended December 31, 2006. In addition, compliance with existing environmental regulations necessitated capital expenditures of $5.0 million in the year ended December 31, 2006. We expect to spend another $10.5 million on such capital expenditures over the next five years. We cannot predict all of the environmental requirements or circumstances that will exist in the future but anticipate that environmental control and protection standards will become increasingly stringent and costly. Based on our experience to date, we do not currently anticipate any material adverse effect on our business or consolidated financial position as a result of future compliance with existing environmental laws and regulations. However, future events, such as changes in existing laws and regulations or their interpretation, more vigorous enforcement policies of regulatory agencies or stricter or different interpretations of existing laws and regulations, may require additional expenditures by us, which may be material. Accordingly, we can provide no assurance that we will not incur significant environmental compliance costs in the future.
In addition, offshore construction and drilling in some areas have been opposed by environmental groups and, in some areas, have been restricted. To the extent laws are enacted or other governmental actions are taken that prohibit or restrict offshore construction and drilling or impose environmental protection requirements that result in increased costs to the oil and gas industry in general and the offshore construction industry in particular, our business and prospects could be adversely affected.
We have been identified as a potentially responsible party at various cleanup sites under CERCLA. CERCLA and other environmental laws can impose liability for the entire cost of cleanup on any of the potentially responsible parties, regardless of fault or the lawfulness of the original conduct. Generally, however, where there are multiple responsible parties, a final allocation of costs is made based on the amount and type of wastes disposed of by each party and the number of financially viable parties, although this may not be the case with respect to any particular site. We have not been determined to be a major contributor of wastes to any of these sites. On the basis of our relative contribution of waste to each site, we expect our share of the ultimate liability for the various sites will not have a material adverse effect on our consolidated financial position, results of operations or liquidity in any given year.
Environmental remediation projects have been and continue to be undertaken at certain of our current and former plant sites. During the fiscal year ended March 31, 1995, we decided to close B&W’s nuclear manufacturing facilities in Parks Township, Armstrong County, Pennsylvania (the “Parks Facilities”), and B&W proceeded to decommission the facilities in accordance with its then-existing license from the Nuclear Regulatory Commission (the “NRC”). B&W subsequently transferred the facilities to BWXT in the fiscal year ended March 31, 1998. During the fiscal year ended March 31, 1999, BWXT reached an agreement with the NRC on a plan that provided for the completion of facilities dismantlement and soil restoration by 2001 and license termination in 2003. BWXT filed its application to terminate the NRC license for the Parks Township facility, and the NRC terminated the license in 2004 and released the facility for unrestricted use. For a discussion of certain civil litigation we are involved in concerning the Parks Facilities, see Note 10 to our consolidated financial statements included in this report.
We perform significant amounts of work for the U.S. Government under both prime contracts and subcontracts and operate certain facilities that are licensed to possess and process special nuclear materials. As a result of these activities, we are subject to continuing reviews by governmental agencies, including the Environmental Protection Agency and the NRC.
The NRC’s decommissioning regulations require BWXT to provide financial assurance that it will be able to pay the expected cost of decommissioning its facilities at the end of their service lives. BWXT will continue to provide financial assurance aggregating $24.5 million during the year ending December 31, 2007 with existing letters of credit for the ultimate decommissioning of all its licensed facilities, except one. This one facility, which represents the largest portion of BWXT’s eventual decommissioning costs, has provisions in its government contracts pursuant to which all of its decommissioning costs and financial assurance obligations are covered by the DOE.
The demand for power generation services and products can be influenced by state and federal governmental legislation setting requirements for utilities related to operations, emissions and environmental impacts. The legislative process is unpredictable and includes a platform that continuously seeks to increase the restrictions on power producers. Potential legislation limiting emissions from power plants, including carbon dioxide, could affect our markets and the demand for our products and services in our Power Generation Systems segment.
At December 31, 2006 and 2005, we had total environmental reserves (including provisions for the facilities discussed above) of $18.6 million and $14.9 million, respectively. Of our total environmental reserves at December 31, 2006 and 2005, $9.7 million and $5.8 million, respectively, were included in current liabilities. Inherent in the estimates of those reserves and recoveries are our expectations regarding the levels of contamination, decommissioning costs and recoverability from other parties, which may vary significantly as decommissioning activities progress. Accordingly, changes in estimates could result in material adjustments to our operating results, and the ultimate loss may differ materially from the amounts we have provided for in our consolidated financial statements.
J. CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.
From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company. These statements may include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. In addition, sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.
In addition, various statements in this Annual Report on Form 10-K, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Those forward-looking statements appear in Item 1 - “Business” in Part I of this report and in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in the notes to our
consolidated financial statements in Item 8 of Part II of this report and elsewhere in this report. These forward-looking statements speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
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general economic and business conditions and industry trends;
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general developments in the industries in which we are involved;
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decisions about offshore developments to be made by oil and gas companies;
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decisions on spending by the U.S. Government and electric power generating companies;
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the highly competitive nature of most of our businesses;
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the ability of our suppliers to deliver raw materials in sufficient quantities and in a timely manner;
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our future financial performance, including compliance with covenants in our credit agreements and other debt instruments and availability, terms and deployment of capital;
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the continued availability of qualified personnel;
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the operating risks normally incident to offshore construction operations and nuclear operations;
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changes in, or our failure or inability to comply with, government regulations and adverse outcomes from legal and regulatory proceedings;
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changes in, and liabilities relating to, existing or future environmental regulatory matters;
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rapid technological changes;
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the realization of deferred tax assets, including through the reorganization we completed in December 2006;
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the consequences of significant changes in interest rates and currency exchange rates;
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difficulties we may encounter in obtaining regulatory or other necessary approvals of any strategic transactions;
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social, political and economic situations in foreign countries where we do business, including countries in the Middle East and Asia Pacific and the former Soviet Union;
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the possibilities of war, other armed conflicts or terrorist attacks;
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the effects of asserted and unasserted claims;
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our ability to obtain surety bonds and letters of credit;
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our ability to maintain builder’s risk, liability, property and other insurance in amounts and on terms we consider adequate and at rates that we consider economical;
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the aggregated risks retained in our insurance captives; and
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the impact of the insurance coverage surrendered as part of the B&W Chapter 11 Settlement.
We believe the items we have outlined above are important factors that could cause estimates in our financial statements to differ materially from actual results and those expressed in a forward-looking statement made in this report or elsewhere by us or on our behalf. We have discussed many of these factors in more detail elsewhere in this report. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises, except as required by applicable securities laws and regulations. We advise our security holders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.
K. AVAILABLE INFORMATION
Our website address is www.mcdermott.com. We make available through this website under “SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, statements of beneficial ownership of securities on Forms 3, 4 and 5 and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission (the “SEC”). We have also posted on our website our: Corporate Governance
Guidelines; Code of Ethics for our Chief Executive Officer and Senior Financial Officers; Board of Directors Conflicts of Interest Policies and Procedures; Officers, Board Members and Contact Information; By-laws; and charters for the Audit, Governance, Compensation and Finance Committees of our Board.
Item 1A.
Item 1A. RISK FACTORS
Our Offshore Oil and Gas Construction segment derives substantially all its revenues from companies in the oil and gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.
The demand for offshore construction services has traditionally been cyclical, depending primarily on the capital expenditures of oil and gas companies for construction of development projects. These capital expenditures are influenced by such factors as:
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prevailing oil and gas prices;
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expectations about future prices;
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the cost of exploring for, producing and delivering oil and gas;
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the sale and expiration dates of available offshore leases;
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the discovery rate of new oil and gas reserves in offshore areas;
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domestic and international political, military, regulatory and economic conditions;
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technological advances; and
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the ability of oil and gas companies to generate funds for capital expenditures.
Prices for oil and gas have historically been extremely volatile and have reacted to changes in the supply of and demand for oil and natural gas (including changes resulting from the ability of the Organization of Petroleum Exporting Countries to establish and maintain production quotas), domestic and worldwide economic conditions and political instability in oil producing countries. We anticipate prices for oil and natural gas will continue to be volatile and affect the demand for and pricing of our offshore construction services. A material decline in oil or natural gas prices or activities over a sustained period of time could materially adversely affect the demand for our offshore construction services and, therefore, our results of operations and financial condition.
Our Power Generation Systems segment derives substantially all its revenues from electric power generating companies and other steam-using industries, with demand for its services and products depending on capital expenditures in these historically cyclical industries.
The demand for power generation services and products depends primarily on the capital expenditures of electric power generating companies, paper companies and other steam-using industries. These capital expenditures are influenced by such factors as:
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prices for electricity, along with the cost of production and distribution;
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prices for natural resources such as coal and natural gas;
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demand for electricity, paper and other end products of steam-generating facilities;
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availability of other sources of electricity, paper or other end products;
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requirements for environmental improvements;
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level of capacity utilization at operating power plants, paper mills and other steam-using facilities;
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requirements for maintenance and upkeep at operating power plants and paper mills to combat the accumulated effects of wear and tear;
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ability of electric generating companies and other steam users to raise capital; and
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relative prices of fuels used in boilers, compared to prices for fuels used in gas turbines and other alternative forms of generation.
A material decline in capital expenditures by electric power generating companies, paper companies and other steam-using industries over a sustained period of time could materially and adversely affect the demand for our power generation services and products and our results of operations and financial condition.
War, other armed conflicts or terrorist attacks could have a material adverse effect on our business.
The war in Iraq and subsequent terrorist attacks and unrest have caused instability in the world’s financial and commercial markets, have significantly increased political and economic instability in some of the geographic areas in which we operate and have contributed to high levels of volatility in prices for oil and gas. The continuing instability and unrest in Iraq, as well as threats of war or other armed conflict elsewhere, may cause further disruption to financial and commercial markets and contribute to even higher levels of volatility in prices for oil and gas. In addition, the continued unrest in Iraq could lead to acts of terrorism in the United States or elsewhere, and acts of terrorism could be directed against companies such as ours. Also, acts of terrorism and threats of armed conflicts in or around various areas in which we operate, such as the Middle East and Indonesia, could limit or disrupt our markets and operations, including disruptions from evacuation of personnel, cancellation of contracts or the loss of personnel or assets. Armed conflicts, terrorism and their effects on us or our markets may significantly affect our business and results of operations in the future.
We are subject to risks associated with contractual pricing in our industries, including the risk that, if our actual costs exceed the costs we estimate on our fixed-price contracts, our profitability will decline, and we may suffer losses.
Because of the highly competitive nature of the industries in which our Offshore Oil and Gas Construction and Power Generation Systems segments perform, these segments have a substantial number of their projects on a fixed-price basis. We attempt to cover increased costs of anticipated changes in labor, material and service costs of long-term contracts, either through estimates of cost increases, which are reflected in the original contract price, or through price escalation clauses. Despite these attempts, however, the cost and gross profit we realize on a fixed-price contract could vary from the estimated amounts because of changes in job conditions, variations in labor and equipment productivity and increases in the cost of raw materials, particularly steel, over the term of the contract. These variations and the risks generally inherent in these industries may result in actual revenues or costs being different from those we originally estimated and may result in reduced profitability or losses on projects.
In addition, we recognize revenues under our long-term contracts in our segments on a percentage-of-completion basis. Accordingly, we review contract price and cost estimates periodically as the work progresses and reflect adjustments proportionate to the percentage of completion in income in the period when we revise those estimates. To the extent these adjustments result in a reduction or an elimination of previously reported profits with respect to a project, we would recognize a charge against current earnings, which could be material. Our current estimates of our contract costs and the profitability of our long-term projects could change, and adjustments to overall contract costs may continue to be significant in future periods.
We face risks associated with investing in foreign subsidiaries and joint ventures, including the risk that we may be restricted in our ability to access the cash flows or assets of these entities.
We conduct some operations through foreign subsidiaries and joint ventures. We do not manage all of these entities. Even in those joint ventures that we manage, we are often required to consider the interests of our joint venture partners in connection with decisions concerning the operations of the joint ventures. Arrangements involving these subsidiaries and joint ventures may restrict us from gaining access to the cash flows or assets of these entities. In addition, these foreign subsidiaries and joint ventures sometimes face governmentally imposed restrictions on their abilities to transfer funds to us. At December 31, 2006, JRM had approximately $28 million in accounts and notes receivable due from its former joint venture in Mexico. A note receivable is attributable to the sale of JRM’s DB17 vessel during the quarter ended September 30, 2004. This joint venture has experienced liquidity problems. Recognition of a gain of approximately $5.4 million on the sale of the DB17 is currently being deferred. On October 17, 2006, JRM reached an agreement with its partner and terminated JRM’s interest in this joint venture. The financial impact of this transaction is included in our consolidated results of operations. JRM expects to collect all net accounts and notes receivable currently owed from this joint venture. In the year ended December 31, 2006, JRM recorded an impairment loss totaling approximately $16.4 million attributable to currency translation losses recorded in accumulated other comprehensive loss.
Our international operations are subject to political, economic and other uncertainties not encountered in our domestic operations.
We derive a significant portion of our revenues from international operations, including customers in the Middle East. Our international operations are subject to political, economic and other uncertainties not generally encountered in our U.S. operations. These include:
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risks of war, terrorism and civil unrest;
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expropriation, confiscation or nationalization of our assets;
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renegotiation or nullification of our existing contracts;
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changing political conditions and changing laws and policies affecting trade and investment;
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the overlap of different tax structures; and
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the risks associated with the assertion of foreign sovereignty over areas in which our operations are conducted.
Our Offshore Oil and Gas Construction segment may be particularly susceptible to regional conditions that may adversely affect its operations. Its major marine construction vessels typically require relatively long periods of time to mobilize over long distances, which could affect our ability to withdraw them from areas of conflict.
Various foreign jurisdictions have laws limiting the right and ability of foreign subsidiaries and joint ventures to pay dividends and remit earnings to affiliated companies. Our international operations sometimes face the additional risks of fluctuating currency values, hard currency shortages and controls of foreign currency exchange.
Our operations are subject to operating risks and limits on insurance coverage, which could expose us to potentially significant liability costs.
We are subject to a number of risks inherent in our operations, including:
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accidents resulting in injury to or the loss of life or property;
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environmental or toxic tort claims, including delayed manifestation claims for personal injury or loss of life;
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pollution or other environmental mishaps;
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hurricanes, tropical storms and other adverse weather conditions;
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mechanical failures;
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collisions;
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property losses;
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business interruption due to political action in foreign countries; and
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labor stoppages.
We have been, and in the future we may be, named as defendants in lawsuits asserting large claims as a result of litigation arising from events such as these. Insurance against some of the risks inherent in our operations is either unavailable or available only at rates that we consider uneconomical. Also, catastrophic events, such as the September 11, 2001 terrorist attacks and the hurricane losses of 2005, customarily result in decreased coverage limits, more limited coverage, additional exclusions in coverage, increased premium costs and increased deductibles and self-insured retentions. Risks that are difficult to insure include, among others, the risk of war and confiscation of property in some areas of the world, losses or liability resulting from acts of terrorism, certain risks relating to construction and pollution liability, property located in certain areas of the world and business interruption. Depending on competitive conditions and other factors, we endeavor to obtain contractual protection against certain uninsured risks from our customers. When obtained, such contractual indemnification protection may not be as broad as we desire or may not be supported by adequate insurance maintained by the customer. Such insurance or contractual indemnity protection may not 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.
Additionally, upon the February 22, 2006 effectiveness of the settlement of the Chapter 11 proceedings of B&W and its affiliated debtor subsidiaries, MII and most of its subsidiaries contributed substantial insurance rights to the asbestos personal injury trust, including rights to (1) certain B&W pre-1979 primary and excess insurance coverages and (2) certain 1979-1986 excess insurance coverage of MII and its affiliates, including JRM, MHI, BWXT and B&W, which 1979-1986 excess policies had an aggregate face value of available limits of coverage of approximately $1.15 billion. These insurance rights provided cover for, among other things, asbestos and other
personal injury claims, subject to the terms and conditions of such policies. With the contribution of these insurance rights to the asbestos personal injury trust, MII and its affiliates, including JRM, MHI, BWXT and B&W, may have underinsured or uninsured exposure for non-B&W-derivative asbestos claims or other personal injury or other claims that would have been insured under these coverages had the insurance rights not been contributed to the asbestos personal injury trust.
BWXT, through two of its dedicated limited liability companies, has management and operating agreements with the U.S. Government for the Y-12 and Pantex facilities. Most insurable liabilities arising from these sites are not protected in our corporate insurance program but rely on government contractual agreements and certain specialized self-insurance programs funded by the U.S. Government. The U. S. Government has historically fulfilled its contractual agreement to reimburse for insurable claims, and we expect it to continue this process during our administration of these two facilities. However, it should be noted that, in most situations, the U. S. Government is contractually obligated to pay, subject to the availability of authorized government funds.
We have captive insurers which provide certain coverages for our subsidiary entities and related coverages. Claims as a result of our operations, could adversely impact the ability of these captive insurers to respond to all claims presented, although we believe such a result is unlikely.
We depend on significant customers, including the U.S. Government.
Our three segments derive a significant amount of their revenues and profits from a relatively small number of customers. The inability of these segments to continue to perform services for a number of their large existing customers, if not offset by contracts with new or other existing customers, could have a material adverse effect on our business and operations.
Our significant customers include federal government agencies and utilities. In particular, our Government Operations segment derives substantially all its revenue from the U.S. Government. Some of our large multi-year contracts with the U.S. Government are subject to annual funding determinations. U.S. Government budget restraints and other factors affecting these governments may adversely affect our business.
We may not be able to compete successfully against current and future competitors.
Most industry segments in which we operate are highly competitive. Some of our competitors or potential competitors have greater financial or other resources than we have. Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics than those of our products and services. This factor is significant to our segments’ businesses, particularly in the Offshore Oil and Gas Construction segment, where capital investment is critical to our ability to compete.
The loss of the services of one or more of our key personnel, or our failure to attract, assimilate and retain trained personnel in the future, could disrupt our operations and result in loss of revenues.
Our success depends on the continued active participation of our executive officers and key operating personnel. The unexpected loss of the services of any one of these persons could adversely affect our operations.
Our operations require the services of employees having the technical training and experience necessary to obtain the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. If either of these events occurred for a significant period of time, our financial condition and results of operations could be adversely impacted.
A substantial number of our employees are members of labor unions. Although we expect to renew our current union contracts without incident, if we are unable to negotiate acceptable new contracts with our unions in the future,
we could experience strikes or other work stoppages by the affected employees, and new contracts could result in increased operating costs attributable to both union and non-union employees. If any such strikes or other work stoppages were to occur, or if our other employees were to become represented by unions, we could experience a significant disruption of our operations and higher ongoing labor costs.
We are subject to government regulations that may adversely affect our future operations.
Many aspects of our operations and properties are affected by political developments and are subject to both domestic and foreign governmental regulations, including those relating to:
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construction and equipping of production platforms and other offshore facilities;
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marine vessel safety;
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currency conversions and repatriation;
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oil exploration and development;
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clean air and environmental protection legislation;
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taxation of foreign earnings and earnings of expatriate personnel; and
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use of local employees and suppliers by foreign contractors.
In addition, our Offshore Oil and Gas Construction segment depends on the demand for its services from the oil and gas industry and, therefore, is affected by changing taxes, price controls and other laws and regulations relating to the oil and gas industry generally. The adoption of laws and regulations curtailing offshore exploration and development drilling for oil and gas for economic and other policy reasons would adversely affect the operations of our Offshore Oil and Gas Construction segment by limiting the demand for its services.
Our Power Generation Systems segment depends primarily on the demand for its services from electric power generating companies and other steam-using customers. The demand for power generation services and products can be influenced by state and federal governmental legislation setting requirements for utilities related to operations, emissions and environmental impacts. The legislative process is unpredictable and includes a platform that continuously seeks to increase the restrictions on power producers. Potential legislation limiting emissions from power plants, including carbon dioxide, could affect our markets and the demand for our products and services in our Power Generation Systems segment.
We cannot determine the extent to which our future operations and earnings may be affected by new legislation, new regulations or changes in existing regulations.
Environmental laws and regulations and civil liability for contamination of the environment or related personal injuries may result in increases in our operating costs and capital expenditures and decreases in our earnings and cash flow.
Governmental requirements relating to the protection of the environment, including solid waste management, air quality, water quality, the decontamination and decommissioning of former nuclear manufacturing and processing facilities and cleanup of contaminated sites, have had a substantial impact on our operations. These requirements are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party without regard to negligence or fault and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. Our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate. Such expenditures and liabilities may adversely affect our business, results of operations or financial condition. See Section H in Item 1 above for further information. In addition, some of our operations and the operations of predecessor owners of some of our properties have exposed us to civil claims by third parties for liability resulting from contamination of the environment or personal injuries caused by releases of hazardous substances into the environment. For a discussion of legal proceedings of this nature in which we are currently involved, see Note 10 to our consolidated financial statements included in this report.
Our internal controls may not be sufficient to achieve all stated goals and objectives.
Our internal controls and procedures were developed through a process in which our management applied its judgment in assessing the costs and benefits of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding the control objectives. You should note that the design of any system of internal controls and procedures is based in part upon various assumptions about the likelihood of future events, and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.
We are subject to other risks including legal proceedings that we discuss in other sections of this annual report.
For discussions of various factors that affect the demand for our products and services in our segments, see the discussions under the heading “Factors Affecting Demand” in each of Sections B, C, and D of Item 1 above. For a discussion of our insurance coverages and uninsured exposures, see Section G of Item 1 above. For discussions of various legal proceedings in which we are involved, in addition to those we refer to above, see Note 10 to our consolidated financial statements included in this report. In addition to the risks we describe or refer to above, we are subject to other risks, contingencies and uncertainties, including those we have referred to under the heading “Cautionary Statement Concerning Forward-Looking Statements” in Section J of Item 1 above.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS
None
Item 2.
Item 2. PROPERTIES
For a description of our significant properties, see Item 1, Section B., “Offshore Oil and Gas Construction - Offshore Oil and Gas Construction Vessels and Properties,” Section C., “Government Operations - Properties,” and Section D., “Power Generation Systems - Properties.” We consider each of our significant properties to be suitable for its intended use.
Item 3.
Item 3. LEGAL PROCEEDINGS
The information set forth under the heading “Investigations and Litigation” in Note 10, “Contingencies and Commitments,” to our consolidated financial statements included in this report is incorporated by reference into this Item 3.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
We did not submit any matter to a vote of security holders, through the solicitation of proxies or otherwise, during the quarter ended December 31, 2006.
PART II
Item 5.
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange. In accordance with Section 303A.12(a) of the New York Stock Exchange Listed Company’s Manual, we submitted the Annual CEO Certification to the New York Stock Exchange in 2006. Additionally, we filed certifications of the Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 32.1 and 32.2, respectively, included in this report. High and low stock prices by quarter in the years ended December 31, 2006 and 2005, as adjusted for the three-for-two stock split effected in May 2006, were as follows:
YEAR ENDED DECEMBER 31, 2006
YEAR ENDED DECEMBER 31, 2005
We have not paid cash dividends on MII’s common stock since the second quarter of 2000 and do not have any plans to reinstate a cash dividend at this time. Our Board of Directors will evaluate our cash dividend policy from time to time.
As of December 31, 2006, there were approximately 3,120 record holders of our common stock.
The following table provides information on our equity compensation plans as of December 31, 2006:
Equity Compensation Plan Information
(1)
Reflects information on our 1992 Senior Management Stock Plan, which is our only equity compensation plan that has not been approved by our stockholders and that has any outstanding awards that have not been exercised. We are no longer authorized to grant new awards under our 1992 Senior Management Stock Plan. See Note 9 to our consolidated financial statements included in this report for more information regarding this plan.
The following graph provides a comparison of our five-year, cumulative total shareholder return from December 2001 through December 2006 to the return of S&P 500 and a peer group:
The peer group used for the five-year comparison was comprised of the following companies:
Item 6.
Item 6. SELECTED FINANCIAL DATA
See Note 18 to our consolidated financial statements included in this report for significant items included in the years ended December 31, 2006 and 2005.
Results for the year ended December 31, 2004 include a before- and after-tax gain on the settlement of our U.K. pension plan of $27.7 million.
Results for the year ended December 31, 2003 include losses on JRM’s three SPAR contracts, the Carina Aries project and the Belanak FPSO project totaling approximately $120 million.
Results for the year ended December 31, 2002 include: impairment charges of $224.7 million, to write off our net investment in B&W of $187.0 million and other related assets totaling $37.7 million, and of $313.0 million related to JRM’s goodwill; a provision for the estimated costs of the settlement of B&W Chapter 11 proceedings of $110.0 million, including associated tax expense of $23.6 million; and a gain on the sale of a subsidiary of $9.4 million, net of taxes of $5.7 million, which is reported in discontinued operations.
Item 7.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Statements we make in the following discussion which express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in
the following discussion as a result of a variety of factors, including the risks and uncertainties we have referred to under the headings “Cautionary Statement Concerning Forward-Looking Statements” and “Risk Factors” in Items 1 and 1A of Part I of this report.
GENERAL
In general, our business segments are composed of capital-intensive businesses that rely on large contracts for a substantial amount of their revenues. Each of our business segments is financed on a stand-alone basis. Our debt covenants limit using the financial resources or the movement of excess cash from one segment for the benefit of the other. For further discussion, see “Liquidity and Capital Resources,” below.
We are currently exploring growth strategies across our segments through acquisitions to expand and complement our existing businesses. As we pursue these opportunities, we expect they would be funded by cash on hand, external financing or both.
Offshore Oil and Gas Construction Segment - Recent Operating Results and Outlook
JRM produced strong financial results in 2006. Based on JRM’s current backlog and the potential for new contract awards, we expect JRM’s strong results to continue in 2007. JRM’s backlog of approximately $4.1 billion at December 31, 2006 is expected to produce revenues for 2007 of approximately $2.1 billion, not including any change orders or new contracts that may be awarded during the year. JRM is actively bidding on and (in some cases) beginning preliminary work on projects that we expect will be awarded to JRM in 2007, subject to successful contract negotiations. In the year ended December 31, 2006, JRM incurred approximately $7 million of expense to mobilize its DB101 vessel.
Currently, JRM’s fabrication yard in Morgan City, Louisiana is not operating at full capacity. In addition, JRM will near completion of its current Caspian operation’s backlog in 2007. The projects in the Caspian region have represented a substantial portion of JRM’s revenue and operating income in recent years. JRM is actively seeking new contracts and awards in all regions in which it operates.
The decision-making process for oil and gas companies in making capital expenditures on offshore construction services for a development project differs depending on whether the project involves new or existing development. In the case of new development projects, the demand for offshore construction services generally follows the exploratory drilling and, in some cases, initial development drilling activities. Based on the results of these activities and evaluations of field economics, customers determine whether to install new platforms and new infrastructure, such as subsea gathering lines and pipelines. For existing development projects, demand for offshore construction services is generated by decisions to, among other things, expand development in existing fields and expand existing infrastructure.
Government Operations Segment - Recent Operating Results and Outlook
BWXT produced strong financial results in 2006. BWXT’s commitment to cost containment, in addition to the potential for new service contract awards, leads management to believe operating results should remain strong in 2007. BWXT’s backlog of approximately $1.3 billion at December 31, 2006 is expected to produce revenues for 2007 of approximately $500 million, not including any change orders or new contracts that may be awarded during the year.
The revenues of our Government Operations segment are largely a function of defense spending by the U.S. Government. As a supplier of major nuclear components for certain U.S. Government programs, BWXT is a significant participant in the defense industry. With BWXT’s unique capability of full life-cycle management of special nuclear materials, facilities and technologies, BWXT is well positioned to continue to participate in the continuing cleanup, operation and management of the DOE’s nuclear sites and weapons complexes.
Power Generation Systems Segment - Recent Operating Results and Outlook
The Power Generation Systems segment consists primarily of the operations of B&W, which were not consolidated in our financial results from February 22, 2000 through February 22, 2006, while B&W and three of its subsidiaries were in Chapter 11 Bankruptcy proceedings. We have included the results of B&W effective from February, 22, 2006, the date on which it exited Chapter 11, in our consolidated financial statements. See Note 20 to our consolidated financial statements included in this report for further information regarding B&W.
B&W produced strong financial results in 2006. Based on B&W’s backlog and potential for new contract awards, we expect operating results for our Power Generation Systems segment to remain strong in 2007. B&W’s backlog of approximately $2.2 billion at December 31, 2006 is expected to produce revenues for 2007 of approximately $1.3 billion, not including any change orders or new contracts that may be awarded during the year. B&W is actively bidding on and (in some cases) beginning preliminary work on projects that we expect will be awarded to B&W in 2007, subject to successful contract negotiations.
B&W’s overall activity depends mainly on the capital expenditures of electric power generating companies and other steam-using industries. B&W’s products and services are capital intensive. As such, customer demand is heavily affected by the variations in customer’s business cycles and by the overall economies of the countries in which they operate.
Stock-Based Compensation
We have several stock-based employee compensation plans, which are described more fully in Note 9 to our consolidated financial statements included in this report. Prior to January 1, 2006, we accounted for these plans using the intrinsic value method under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”), and related interpretations. Effective January 1, 2006, we adopted the provisions of the revised Statement of Financial Accounting Standards (“SFAS”) No. 123, “Share-Based Payment” (“SFAS No. 123(R)”), on a modified prospective application basis. SFAS No. 123(R) eliminates the alternative permitted under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), to use APB No. 25’s intrinsic value method of accounting, under which issuing stock options to employees generally did not result in recognition of compensation. Under the provisions of SFAS No. 123(R) and using the modified prospective application method, we recognize stock-based compensation, net of an estimated forfeiture rate, for all share-based awards granted after December 31, 2005 and granted prior to, but not yet vested as of, December 31, 2005 on a straight-line basis over the requisite service periods of the awards, which is generally equivalent to the vesting term. Under the modified prospective application, the results of prior periods are not restated.
Pursuant to the adoption of SFAS No. 123(R), we recognized stock-based compensation expense of $4.4 million related to employee stock options during the year ended December 31, 2006. During the years ended December 31, 2005 and 2004, there was no stock-based compensation expense for employee stock options, other than for stock options subject to variable accounting. These stock options subject to variable accounting resulted from the cancellation and reissuance of stock options during the year ended December 31, 2000. Under APB No. 25 and its related interpretations, the cancellation and reissuance of stock options within six months of each other triggered mark-to-market accounting. For our other stock-based compensation awards, such as restricted stock and performance units, the adoption of SFAS No. 123(R) did not significantly change our accounting policies for the recognition of compensation expense, as we have recognized expense for those awards in prior periods. Total compensation expense recognized for the years ended December 31, 2006, 2005 and 2004 was as follows:
The impact on basic earnings per share of stock-based compensation expense recognized for the years ended December 31, 2006, 2005 and 2004 was $0.13, $0.01 and $0.05 per share, respectively, and on diluted earnings per share was $0.12, $0.01 and $0.05 per share, respectively.
As of December 31, 2006, total unrecognized estimated compensation expense related to nonvested awards was $14.7 million, net of estimated tax benefits of $6.9 million. The total gross unrecognized estimated compensation expense of $21.6 million consists of $3.6 million for stock options, $0.2 million for restricted stock and $17.8 million for performance shares, which are expected to be recognized over weighted average periods of 0.9 years, 0.2 years and 2.4 years, respectively. Performance and deferred stock units are marked-to-market at the end of each quarter, so there was no unrecognized compensation expense as of December 31, 2006.
The determination of the fair value of a share-based payment award on the date of grant using an option-pricing model requires the input of highly subjective assumptions, such as the expected life of the award and stock price volatility. Prior to the adoption of SFAS No. 123(R), we used the Black-Scholes option-pricing model (“Black-Scholes”) for the pro forma information required to be disclosed under SFAS No. 123, as originally issued, and we believe this model will continue to provide appropriate fair values under the provisions of SFAS No. 123(R). See Note 9 to our consolidated financial statements included in this report for further discussion on stock-based compensation.
Other
The results of Talleres Navales del Golfo, S.A. de C.V. (“TNG”), previously a component of our Offshore Oil and Gas Construction segment, are reported in discontinued operations. We sold TNG in April 2006. See Note 2 to our consolidated financial statements included in this report for further information on discontinued operations.
Effective December 31, 2006, in accordance with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” we recorded an additional pension and post-retirement liability of approximately $145 million and a reduction in intangible assets of approximately $24 million.
Effective March 31, 2006, benefit accruals under all of our domestic qualified pension plans other than the JRM qualified pension plan (which was frozen in March 2003) ceased for salaried employees hired on or after April 1, 2001. Any pension benefits earned to that date continue to be payable pursuant to the plans upon retirement, but no future benefits will accrue, other than the annual increase in line with the consumer price index, up to 8%, during each year the participants remain employed by us. All affected salaried employees participating in these plans as of March 31, 2006 became fully vested at that time. We will provide future retirement benefits to affected employees by making additional contributions to our thrift plan. While these benefit changes will shift costs from our pension plans to our thrift plan, the overall cost of the retirement program is not expected to change materially from our current contribution or expense levels.
As part of our strategy to continue to provide a competitive compensation package to reward, motivate and retain our employees, we are providing employees (other than participants in the JRM pension plan) with five to 10 years of service as of January 1, 2007 with a one-time, irrevocable opportunity to choose whether to earn benefits under our existing retirement plans or to receive enhanced company contributions under our thrift plan. From February 1, 2007 through March 15, 2007, these employees may choose to do one of the following:
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receive automatic, service-based company contributions under our thrift plan and stop earning benefits under our defined benefit retirement plan as of March 31, 2007. For employees who choose this option, the retirement plan benefit will not reflect any service after March 31, 2007, or any changes in their salary after that date. However, it will escalate in line with the cost of living, as measured by the Consumer Price Index, up to a maximum eight percent a year, for each year the employee remains with us; or
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remain in our defined benefit retirement plan and continue earning future benefits under this plan. Participation in our retirement and thrift plans will remain unchanged under this option.
These employees will have until March 15, 2007 to elect how they wish to earn future pension benefits. If no action is taken, the employee will continue to accrue pension benefits through our defined benefit retirement plan. We do not expect this election to have a material impact on our financial position, results of operations or cash flows.
At December 31, 2006, in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” we decreased our minimum pension liability by approximately $124.8 million, primarily due to the increasing of our discount rate in 2006 to 6.0% from 5.75%. At December 31, 2005, we increased our minimum pension liability by approximately $87 million, primarily due to the lowering of our discount rate in 2005 to 5.75% from 6.0%.
Effective December 31, 2004, benefit accruals under the McDermott International, Inc. Supplemental Executive Retirement Plan, amended and restated effective December 1, 1999 (the “Old SERP Plan”), ceased and we adopted the McDermott International, Inc. Supplemental Executive Retirement Plan effective January 1, 2005 (the “New SERP Plan”). The Old SERP Plan was a defined benefit plan, while the New SERP Plan is a defined contribution plan. The cessation of benefits of the Old SERP Plan generally did not affect the rights of retired or disabled participants (or their spouses) who were receiving benefits under that plan as of December 31, 2004. However, some of the retired participants elected to receive a discounted lump-sum distribution in lieu of any future entitlements under the Old SERP Plan. All active participants in the Old SERP Plan on December 31, 2004 became participants in the New SERP Plan on January 1, 2005. We recorded a settlement and curtailment gain of approximately $4.6 million in connection with the cessation of benefits. We also recorded expenses related to the New SERP Plan of approximately $2.9 million, $1.3 million and $1.4 million in the years ended December 31, 2006, 2005 and 2004, respectively.
We derive a significant portion of our revenues from foreign operations. As a result, international factors, including variations in local economies and changes in foreign currency exchange rates, affect our revenues and operating results. We attempt to limit our exposure to changes in foreign currency exchange rates by attempting to match anticipated foreign currency contract receipts with like foreign currency disbursements. To the extent that we are unable to match the foreign currency receipts and disbursements related to our contracts, we enter into foreign currency derivative instruments to reduce the impact of foreign exchange rate movements on our operating results. Because we generally do not hedge beyond our exposure, we believe this practice minimizes the impact of foreign exchange rate movements on our operating results.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We believe the following are our most critical accounting policies that we apply in the preparation of our financial statements. These policies require our most difficult, subjective and complex judgments, often as a result of the need to make estimates of matters that are inherently uncertain.
Restricted Cash. We record cash as restricted when we are unable to use such cash and cash equivalents freely for general operating purposes.
Contracts and Revenue Recognition. We determine the appropriate accounting method for each of our long-term contracts before work on the project begins. We generally recognize contract revenues and related costs on a percentage-of-completion method for individual contracts or combinations of contracts under the guidelines of the Statement of Position 81-1, Accounting for Performance of Construction-Type and Certain Production-Type Contracts (“SOP 81-1”). The use of this method is based on our experience and history of being able to prepare reasonably
dependable estimates of the cost to complete our projects. Under this method, we recognize estimated contract revenue and resulting income based on costs incurred to date as a percentage of total estimated costs. Total estimated costs, and resulting contract income, are affected by changes in the expected cost of materials and labor, productivity, scheduling and other factors. Additionally, external factors such as weather, customer requirements and other factors outside of our control, may affect the progress and estimated cost of a project’s completion and, therefore, the timing of revenue and income recognition. We routinely review estimates related to our contracts, and revisions to profitability are reflected in the quarterly and annual earnings we report. SOP 81-1 provides that the use of percentage-of-completion accounting requires the ability to make reasonably dependable estimates.
For contracts as to which we are unable to estimate the final profitability except to assure that no loss will ultimately be incurred, we recognize equal amounts of revenue and cost until the final results can be estimated more precisely. For these deferred profit recognition contracts, we recognize revenue and cost equally and only recognize gross margin when probable and reasonably estimable, which we generally determine to be when the contract is approximately 70% complete. We treat long-term construction contracts that contain such a level of risk and uncertainty that estimation of the final outcome is impractical except to assure that no loss will be incurred as deferred profit recognition contracts. We accounted for JRM’s Dolphin Upstream Facilities project as a deferred recognition contract until its completion during 2006. At December 31, 2006, we have no contracts being accounted for using the deferred profit recognition basis.
Fixed-price contracts are required to be accounted for under the completed-contract method if we are unable to reasonably forecast cost to complete at start-up. For example, if we have no experience in performing the type of work on a particular project and were unable to develop reasonably dependable estimates of total costs to complete, we would follow the completed-contract method of accounting for such projects. Our management’s policy is not to enter into fixed-price contracts without an accurate estimate of cost to complete. However, it is possible that in the time between contract execution and the start of work on a project, we could lose confidence in our ability to forecast cost to complete based on intervening events, including but not limited to experience on similar projects, civil unrest, strikes and volatility in our expected costs. In such a situation, we would use the completed-contract method of accounting for that project. No such contracts were executed in 2006.
For all contracts, if a current estimate of total contract cost indicates a loss on a contract, the projected loss is recognized in full when determined.
Although we continually strive to improve our ability to estimate our contract costs and profitability, adjustments to overall contract costs due to unforeseen events could be significant in future periods. We recognize claims for extra work or for changes in scope of work in contract revenues, to the extent of costs incurred, when we believe collection is probable and can be reasonably estimated. We recognize income from contract change orders or claims when formally agreed with the customer. We reflect any amounts not collected as an adjustment to earnings. We regularly assess the collectibility of contract revenues and receivables from customers.
Inventories. We carry our inventories (principally in B&W, which was not consolidated at December 31, 2005) at the lower of cost or market. We determine cost principally on the first-in-first-out basis, except for certain materials inventories, for which we use the last-in-first-out method.
Property, Plant and Equipment. We carry our property, plant and equipment at depreciated cost, reduced by provisions to recognize economic impairment when we determine impairment has occurred. Factors that impact our determination of impairment include forecasted utilization of equipment and estimates of cash flow from projects to be performed in future periods. Our estimates of cash flow may differ from actual cash flow due to, among other things, technological changes, economic conditions or changes in operating performance. Any changes in such factors may negatively affect our business segments and result in future asset impairments.
Except for major marine vessels, we depreciate our property, plant and equipment using the straight-line method, over estimated economic useful lives of eight to 40 years for buildings and two to 28 years for machinery and equipment. We depreciate major marine vessels using the units-of-production method based on the utilization of each vessel. Our depreciation expense calculated under the units-of-production method may be less than, equal to or greater than depreciation expense calculated under the straight-line method in any period. The annual depreciation based on
utilization of each vessel will not be less than the greater of 25% of annual straight-line depreciation and 50% of cumulative straight-line depreciation.
We expense the costs of maintenance, repairs and renewals, which do not materially prolong the useful life of an asset, as we incur them, except for drydocking costs. Through December 31, 2006, we accrued estimated drydocking costs for our marine fleet over the period of time between drydockings, generally three to five years. We accrued drydocking costs in advance of the anticipated future drydocking, commonly known as the accrue-in-advance method. We charged actual drydocking costs against the liability when incurred, and we recognized any differences between actual costs and accrued costs over the remaining months of the drydocking cycle. Our actual drydocking costs often differ from our estimates due to the long period between drydockings and the inherent difficulties in estimating cost of vessel repairs and renewals until the drydocking occurs. Pursuant to FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” issued by the Financial Accounting Standards Board (the “FASB”) during September 2006, we will change our accounting policy from the accrue-in-advance method to the deferral method, effective January 1, 2007, as more fully discussed in Note 1 to our consolidated financial statements included in this report.
Self-Insurance. We have several wholly owned insurance subsidiaries that provide workers compensation, employer’s liability, general and automotive liability and workers compensation insurance and from time to time, builder’s risk within certain limits and marine hull to our companies. We may also have business reasons in the future to have these insurance subsidiaries accept other risks which we can not or do not wish to transfer to outside insurance companies. Reserves related to these insurance programs are based on the facts and circumstances specific to the insurance claims, our past experience with similar claims, loss factors and the performance of the outside insurance market for the type of risk at issue. The actual outcome of insured claims could differ significantly from estimated amounts. We maintain actuarially determined accruals in our consolidated balance sheets to cover self-insurance retentions for the coverage discussed above. These accruals are based on certain assumptions developed utilizing historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted as required based upon actual claim settlements and reported claims. These loss estimates and accruals recorded in our financial statements for claims have historically been reasonable in light of the actual amount of claims paid.
Pension Plans and Postretirement Benefits. We estimate income or expense related to our pension and postretirement benefit plans based on actuarial assumptions, including assumptions regarding discount rates and expected returns on plan assets. We determine our discount rate based on a review of published financial data and discussions with our actuary regarding rates of return on high-quality fixed-income investments currently available and expected to be available during the period to maturity of our pension obligations. Based on historical data and discussions with our actuary, we determine our expected return on plan assets based on the expected long-term rate of return on our plan assets and the market-related value of our plan assets. Changes in these assumptions can result in significant changes in our estimated pension income or expense and our consolidated financial position. We revise our assumptions on an annual basis based upon changes in current interest rates, return on plan assets and the underlying demographics of our workforce. These assumptions are reasonably likely to change in future periods and may have a material impact on future earnings. Effective December 31, 2006, we adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”), which resulted in the recognition of the funded status of our defined benefit pension plans and postretirement plans in our consolidated balance sheets included in this report. See Note 6 to our consolidated financial statements included in this report for additional information related to SFAS No. 158.
Loss Contingencies. We estimate liabilities for loss contingencies when it is probable that a liability has been incurred and the amount of loss is reasonably estimable. We provide disclosure when there is a reasonable possibility that the ultimate loss will exceed the recorded provision or if such loss is not reasonably estimable. We are currently involved in some significant litigation, as discussed in Note 10 to our consolidated financial statements included in this report. We have accrued our estimates of the probable losses associated with these matters. However, our losses are typically resolved over long periods of time and are often difficult to estimate due to the possibility of multiple actions by third parties. Therefore, it is possible future earnings could be affected by changes in our estimates related to these matters.
Goodwill. SFAS No. 142, “Goodwill and Other Intangible Assets,” requires us to perform periodic testing for impairment. It requires a two-step impairment test to identify potential goodwill impairment and measure the amount of a goodwill impairment loss. The first step of the test compares the fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill impairment test is performed to measure the amount of the impairment loss, if any. Both steps of goodwill impairment testing involve significant estimates.
Asset Retirement Obligations and Environmental Clean-up Costs. We accrue for future decommissioning of our nuclear facilities that will permit the release of these facilities to unrestricted use at the end of each facility’s life, which is a requirement of our licenses from the Nuclear Regulatory Commission. In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), we record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When we initially record such a liability, we capitalize a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of a liability, we will settle the obligation for its recorded amount or incur a gain or loss. SFAS No. 143 applies to environmental liabilities associated with assets that we currently operate and are obligated to remove from service. For environmental liabilities associated with assets that we no longer operate, we have accrued amounts based on the estimated costs of clean-up activities, net of the anticipated effect of any applicable cost-sharing arrangements. We adjust the estimated costs as further information develops or circumstances change. An exception to this accounting treatment relates to the work we perform for one facility, for which the U.S. Government is obligated to pay all the decommissioning costs.
Deferred Taxes. We record a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized. We believe that the deferred tax asset recorded as of December 31, 2006 is realizable through carrybacks, future reversals of existing taxable temporary differences and future taxable income. If we were to subsequently determine that we would be able to realize deferred tax assets in the future in excess of our net recorded amount, an adjustment to deferred tax assets would increase earnings for the period in which such determination was made. We will continue to assess the adequacy of the valuation allowance on a quarterly basis. Any changes to our estimated valuation allowance could be material to our consolidated financial condition and results of operations. In June 2006, FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), to clarify the accounting for uncertainty in income taxes recognized in an entity’s financial statement in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 is effective for fiscal years beginning after December 15, 2006, as more fully discussed in Notes 1 and 4 to our consolidated financial statements included in this report.
Warranty. We account for warranty costs to satisfy contractual warranty requirements as a component of our total contract cost estimate on the related contracts for our Offshore Oil and Gas Construction segment or as an accrued estimated expense recognized in conjunction with the associated revenue on the related contracts for our Government Operations and Power Generation Systems segments. In addition, we make specific provisions where we expect the actual warranty costs to significantly exceed the accrued estimates. In our Offshore Oil and Gas Construction segment, warranty periods are generally limited, and we have had minimal warranty cost in prior years. Factors that impact our estimate of warranty costs include prior history of warranty claims and our estimates of future costs of materials and labor. Our future warranty provisions may vary from what we have experienced in the past.
Stock-Based Compensation. Effective January 1, 2006, we adopted the provisions of the revised SFAS No. 123, “Share-Based Payment” (“SFAS No. 123(R)”), on a modified prospective application basis. Under the provisions of SFAS No. 123(R) and using the modified prospective application method, we recognize stock-based compensation, net of an estimated forfeiture rate, for all share-based awards granted after December 31, 2005 and granted prior to, but not yet vested as of, December 31, 2005 on a straight-line basis over the requisite service periods of the awards, which is generally equivalent to the vesting term.
For further discussion of recently adopted accounting standards, see Note 1 to our consolidated financial statements included in this report.
YEAR ENDED DECEMBER 31, 2006 COMPARED TO YEAR ENDED DECEMBER 31, 2005
Offshore Oil and Gas Construction
Revenues increased 30.0%, or $371.4 million, to $1.6 billion in 2006, primarily due to increased activities in our Middle East region, an increase in offshore projects worldwide and increased activities in our Asia Pacific region. These increases were partially offset by a decrease in activities in the Caspian region and a decrease in fabrication activities in our Americas region.
Segment operating income, which is before equity in income (loss) of investees and gains (losses) on asset disposals and impairments-net, increased $60.2 million from $149.7 million in 2005 to $209.9 million in 2006. Approximately $15.0 million of this increase is attributable to profit deferred since the inception of a project with Dolphin Energy Ltd., which we accounted for under our deferred profit recognition policy, as discussed above. As of December 31, 2006, the project was substantially complete and the profit earned since inception to date was recognized. In addition, segment operating income increased in the year ended December 31, 2006 compared to the year ended December 31, 2005 due to increased activities in our Middle East and Asia Pacific regions, increased offshore projects worldwide and higher margins from the Caspian and Asia Pacific regions. These increases were partially offset by a decrease in fabrication activities in our Americas region and a decrease in all other operations. In addition, general and administrative expenses increased in the year ended December 31, 2006 due to increases in departmental expenses.
Gains (losses) on asset disposals and impairments - net decreased $22.6 million to a loss of $16.2 million in the year ended December 31, 2006 from a gain of $6.4 million in the year ended December 31, 2005. This reduction was primarily attributable to an impairment of $16.4 million associated with our terminated joint venture in Mexico in the year ended December 31, 2006 and gains on sales of various non-strategic assets in the year ended December 31, 2005.
Equity in income (loss) of investees decreased $5.7 million from a gain of $2.8 million in the year ended December 31, 2005 to a loss of $2.9 million in the year ended December 31, 2006, primarily attributable to our share of expenses in our deepwater solutions joint venture.
Government Operations
Revenues increased approximately 4.8%, or $29.0 million, to $630.1 million in the year ended December 31, 2006, primarily due to higher volumes in the manufacture of nuclear components for certain U.S. Government programs along with higher volumes from our other government operations producing fuel for research test reactors and DOE fuel development for commercial reactors. Also, contributing to this increase was higher volume from our management and operating contract for U.S. Government-owned facilities in New Mexico, along with higher volumes in commercial nuclear environmental services work including additional environmental engineering work at our Pennsylvania location. These increases were partially offset by lower commercial downblending work due to the completion of our contract to downblend 50 metric tons of highly enriched uranium to low enriched uranium. We also experienced lower revenues in the year ended December 31, 2006 from our fuel cell development project, which we terminated in 2006.
Segment operating income, which is before equity income of investees and gains on asset disposals and impairments - net, increased $14.8 million to $82.8 million in the year ended December 31, 2006, primarily attributable to cost and efficiency improvements resulting from our consolidation of two operating divisions into BWXT’s Nuclear Operations Division and continued productivity improvements. In addition, we experienced an increase in volumes and margins of our other government operations producing fuel for research test reactors and DOE fuel development for commercial reactors. We also experienced an increase in our commercial nuclear environmental services activity, including additional environmental engineering work, and improved performance from our environmental labs. Also, contributing to this increase was lower spending on research and development activity in the year ended December 31, 2006, and increased fees for a management and operating contract for U.S. Government-owned facilities in New Mexico. These increases were partially offset by lower fees from subcontracting activity at a DOE site cleanup in Ohio
and lower commercial downblending work due to the completion of our contract, as discussed above. In addition, we experienced higher pension expense, higher selling, general and administrative expenses and an increase to our provision for an environmental liability in Pennsylvania in the year ended December 31, 2006.
Gains on asset disposals and impairments - net increased $1.0 million in the year ended December 31, 2006, attributable to the sale of noncore machinery.
Equity in income of investees decreased $3.5 million to $27.8 million in the year ended December 31, 2006, primarily due to our decision to terminate our research and development joint venture, along with decreased scope at our joint venture in Idaho. These decreases were partially offset by improved fees at our sites in Tennessee and Texas in the year ended December 31, 2006.
Power Generation Systems
Our Power Generation Systems segment consists primarily of B&W, which was not consolidated in the year ended December 31, 2005. The revenues and segment operating income of this segment for the year ended December 31, 2006 were substantially all attributable to B&W, which was reconsolidated into our results effective February 22, 2006 and include approximately ten months’ results in the year ended December 31, 2006. B&W’s revenues and segment operating income in the year ended December 31, 2006 resulted primarily from utility steam system fabrication, fabrication and construction of plant enhancement projects, replacement parts, boiler cleaning equipment, nuclear services and replacement nuclear steam generators.
Equity in income of investees increased $6.1 million to $12.5 million in the year ended December 31, 2006, primarily due to income recognized from a joint venture in China, which was placed on the equity method of accounting during the year ended December 31, 2006.
Corporate
Unallocated Corporate expenses decreased $10.0 million in the year ended December 31, 2006 from $39.9 million to $29.9 million, primarily attributable to lower legal expenses related to B&W’s Chapter 11 proceedings in 2006 compared to 2005. This decrease was partially offset by higher qualified pension plan expense in 2006 compared to 2005. We also experienced lower departmental expenses in 2006, and we recorded a favorable adjustment related to the settlement of prior-year litigation in 2006. In addition, we experienced favorable results from our captive insurers in the year ended December 31, 2006, compared to the year ended December 31, 2005.
Other Income Statement Items
Interest income increased by $32.5 million to $53.6 million in the year ended December 31, 2006, primarily due to an increase in average cash equivalents and investments and higher interest rates, as well as settlement from the Canadian taxing authorities with respect to audit issues.
Interest expense decreased by $1.5 million to $30.3 million in the year ended December 31, 2006, primarily due to the retirement of the JRM Secured Notes in June 2006, partially offset by higher interest and associated amortization and costs on our credit facilities.
We recorded other income from an IRS interest expense adjustment for the year ended December 31, 2006, totaling approximately $13.2 million, attributable to a settlement MI reached with U.S. and Canadian tax authorities related to transfer pricing issues. This income was partially offset by an increase in interest expense during the year ended December 31, 2006 totaling approximately $7.5 million for potential U.S. tax deficiencies.
On June 6, 2006, JRM completed a tender offer and used current cash on hand to purchase the entire $200 million in aggregate principal amount outstanding of its secured notes for approximately $249.0 million, including accrued interest of approximately $10.9 million. As a result of this early retirement of debt, we recognized $49.0 million of expense during the year ended December 31, 2006. In addition, in December 2006, B&W retired its $250 million promissory note issued in 2005, as part of its Chapter 11 bankruptcy settlement. This note was recorded in Accrued Cost of The Babcock & Wilcox Company Bankruptcy Settlement on our consolidated balance sheets at its
fair value of approximately $245.3 million. As a result of this retirement, we recognized approximately $4.7 million of expense.
Other-net expense increased by $13.1 million to $13.8 million in the year ended December 31, 2006, primarily due to currency exchange losses in 2006, compared to gains in 2005.
Provision for Income Taxes
For the year ended December 31, 2006, our provision for income taxes increased $10.3 million to $19.2 million, while income before provision for income taxes increased $141.9 million to $348.6 million. Our effective tax rate for the year ended December 31, 2006 was approximately 5.5%, which was primarily due to the valuation allowance adjustment discussed below.
For the year ended December 31, 2006, we reversed $94.1 million of the deferred tax asset valuation allowance recorded against the JRMH deferred tax assets. SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”), provides that a valuation allowance must be established for deferred tax assets when it is more likely than not that the assets will not be realized. SFAS No. 109 also provides that all positive and negative evidence must be evaluated in determining the need for a valuation allowance. As a result of the reorganization of our U.S. legal entities discussed more fully below, we have reevaluated all the positive and negative evidence available to us and have determined that we no longer require a federal deferred tax asset valuation allowance. Accordingly, under the guidelines of SFAS No. 109, we reversed the majority of the JRMH federal deferred tax asset valuation allowance through current period earnings in 2006 by recording a credit to our provision for income taxes.
We completed a reorganization of our MI and JRMH groups of U.S. legal entities into a single consolidated U.S. group effective December 31, 2006. This reorganization provides us with administrative efficiencies, the opportunity to increase the flexibility of our financial structure and returns us to a more tax-efficient legal structure. Prior to 1995, substantially all of the operations of JRMH (formerly our U.S. offshore oil and gas construction business) were combined with MI in a single consolidated U.S. group. In 1995, substantially all our offshore oil and gas construction assets were acquired by JRM in conjunction with JRM’s acquisition of Offshore Pipelines, Inc. (“OPI”). As a result of the acquisition of OPI, MII’s ownership interest in the common stock of JRM was reduced to approximately 64%, with the remaining 36% being publicly traded. The results of JRMH were consequently no longer part of MI’s consolidated U.S. group. In 1999, MII acquired all of the remaining publicly held common stock of JRM, such that MII owned 100% of JRM. A restructuring to achieve the reconsolidation of the JRMH and MI groups was not feasible until 2006, attributable in part to long-running asbestos liability claims against B&W, which ultimately lead B&W to file for Chapter 11 bankruptcy protection. In February 2006, B&W emerged from Chapter 11 bankruptcy protection and was reconsolidated into our results. Subsequent to B&W’s emergence from bankruptcy, action was taken to recombine our JRMH and MI groups, with the final reorganization being completed effective December 31, 2006. Although we will continue to file a separate U.S. tax return for each U.S. group for the year ended December 31, 2006, the current earnings reflect a tax benefit for the JRMH U.S. group, as a result of the reorganization. Beginning with the taxable period commencing January 1, 2007, the results of the former separate U.S. groups will be consolidated, and a single U.S. tax return will be filed. As a consequence, we do not expect to make any federal tax payments in 2007.
As more fully disclosed in Part II of our annual report on Form 10-K for the year ended December 31, 2005, for the year ended December 31, 2005, we reversed our federal deferred tax asset valuation allowance totaling approximately $50.4 million, which eliminated our MI federal deferred tax asset valuation allowance associated with our minimum pension liability. This adjustment recorded for the year ended December 31, 2005 resulted in a benefit in our provision for income taxes of $50.4 million.
We have provided for income taxes based on the tax laws and rates in the countries in which we conduct our operations. MII is a Panamanian corporation that has earned all of its income outside of Panama. As a result, MII is not subject to income tax in Panama. MII and its subsidiaries operate in the United States taxing jurisdiction and various other taxing jurisdictions around the world. Each of these jurisdictions has a regime of taxation that varies from the others. The taxation regimes vary not only with respect to nominal rates but also with respect to the allowability of deductions, credits and other benefits and tax bases (for example, revenue versus income). These variances, along with variances in our mix of income from these jurisdictions, contribute to variability in our effective tax rate.
Income (loss) from continuing operations before provision for (benefit from) income taxes, provision for (benefit from) income taxes and effective tax rates for MII’s major subsidiaries are as follows:
MI is subject to United States federal income tax at a rate of 35%. The effective tax rate of MI is primarily affected by applicable state income taxes on its profitable U.S. subsidiaries, as well as the items discussed below. In the year ended December 31, 2006, MI reached a settlement in a tax dispute with United States and Canadian tax authorities, primarily related to transfer pricing matters, resulting in an adjustment to the tax liability and associated accrued interest established for the disputed item. This favorably impacted MI’s income before income taxes and provision for income taxes by $13.2 million and $4.7 million, respectively. In addition, offsetting tax adjustments related to open years for federal and certain state tax jurisdictions were recorded in the year ended December 31, 2006, along with approximately $4.9 million of related interest expense. Approximately $18 million in tax expense was recorded for the expiration of certain foreign tax credits and via an increase in valuation allowance for foreign credit carryfowards that may expire in the future prior to being utilized.
The effective tax rate of MI for the year ended December 31, 2005 was impacted by the B&W Chapter 11 settlement adjustment recorded in that period, which generated little or no associated U.S income tax effect, and the valuation allowance adjustment discussed above.
JRMH is subject to United States income tax at a rate of 35%. No current United States income tax is payable by JRMH due to its current year loss; however, a tax benefit was recorded for its 2006 operations, due to the U.S. reorganization discussed above. Further, JRMH’s valuation allowance for the realization of deferred tax assets has been adjusted in accordance with SFAS No. 109, as discussed above. In addition, JRMH recorded a net provision for income taxes of approximately $9 million associated with potential U.S. income tax issues.
See Note 4 to our consolidated financial statements included in this report for further information on income taxes.
YEAR ENDED DECEMBER 31, 2005 COMPARED TO YEAR ENDED DECEMBER 31, 2004
Offshore Oil and Gas Construction
Revenues decreased 9%, or $118.9 million, to $1.2 billion in 2005, primarily due to decreases in fabrication activity levels in our Americas and Asia Pacific regions. In addition, offshore activity in our Americas region was also reduced. Fabrication manhours in these regions for 2005 were 40% of 2004 levels, while offshore activity in the Americas experienced a moderate decrease in barge days of approximately 19% in 2005 compared to 2004. These reductions contributed to net decreases in revenue totaling approximately $333.5 million. These decreases, along with a $90.6 million decrease related to the completion of our three Spar projects in 2004, were partially offset by increased fabrication activity in our Middle East and Caspian regions ($38.6 million) and substantial increases in our international offshore activities ($275.2 million). Revenues from other activities in JRM decreased by approximately $2.2 million in the year ended December 31, 2005 compared to the year ended December 31, 2004.
Segment operating income, which is before equity in income of investees and gains on asset disposals and impairments-net, increased $95.9 million from $53.8 million in 2004 to $149.7 million in 2005. This increase was primarily attributable to operating income from offshore construction projects due to the increases in Middle East, Caspian and international offshore activity levels referenced above and improved margins in these regions. These increases were partially offset by decreases in fabrication activity levels in our Americas and Asia Pacific regions and decreases in offshore activity in the Americas region. In addition, general and administrative expenses increased by $7.0 million to $107.3 million, primarily due to increased costs related to systems development and increased legal expenses.
Gains on asset disposals and impairments - net decreased $23.9 million to $6.4 million in 2005 from $30.3 million in 2004. This reduction was attributable to gains on sales of nonstrategic assets in 2004, including the Oceanic 93 and our fabrication facility in Scotland.
Equity in income of investees increased $0.9 million to $2.8 million in 2005, primarily due to the settlement of warranty issues in a joint venture in Europe ($3.1 million). This increase was offset by a decrease in our share of the royalty income recognized in our Spars International Inc. joint venture due to a restructuring of the joint venture.
Government Operations
Revenues increased 8%, or $45.9 million, to $601.0 million in 2005, primarily due to higher volumes in the manufacture of nuclear components for certain U. S. Government programs. Higher volumes in commercial nuclear environmental services work, including the change from equity income recognition to revenue recognition under a subcontract in Idaho, also contributed to this increase. In addition, we experienced higher revenues from downblending of highly enriched uranium to low enriched uranium, which we downblend pursuant to a tolling arrangement. This downblended material is used by U.S. commercial nuclear power plants as fuel to generate electricity. These increases were partially offset by lower revenues at a DOE site in South Carolina and lower revenues associated with the recovery of uranium from process materials for the DOE.
Segment operating income, which is before equity income from investees and gains on asset disposals and impairments-net, decreased $8.7 million to $68.0 million in 2005, primarily due to approximately $18.8 million of pension expense allocated to BWXT in 2005 that was recorded as an unallocated Corporate expense in 2004. In addition, BWXT also experienced higher general and administrative expenses, primarily due to stock-based compensation expense, facility oversight costs, costs related to enterprise system implementation and Sarbanes-Oxley implementation and compliance. These decreases were partially offset by higher volumes and margins from our manufacture of nuclear components for certain U.S. Government programs, our engineering services work for DOE sites and commercial work.
Equity in income from investees decreased $1.3 million to $31.3 million in 2005, primarily due to the change from equity income recognition to revenue recognition under a subcontract in Idaho. This decrease was partially offset by additional fees earned at a site in Tennessee.
Power Generation Systems
Equity in income for investees increased $5.3 million to $6.5 million in 2005, primarily due to income recognized by a joint venture in China.
Corporate
Unallocated Corporate expenses decreased $9.8 million from $49.7 million to $39.9 million, primarily due to the allocation of pension plan expense for the BWXT and B&W pension plans previously recorded as an unallocated Corporate expense in 2004 totaling approximately $60.4 million. In 2005, we recorded expenses associated with these plans totaling approximately $18.8 million in our Government Operations segment and $34.9 million in B&W, respectively. Also, in 2004, we recognized a gain on the curtailment of our pension plan in the United Kingdom totaling $27.7 million. The decrease in pension expense recorded as an unallocated Corporate expense for 2005 compared to 2004 was partially offset by an increase in stock-based compensation expense attributable to the increase in our stock price in the year ended December 31, 2005. In addition, in 2005, we experienced increased legal and professional fees associated with B&W’s Chapter 11 proceedings.
Effective January 1, 2005, we began allocating to our Government Operations segment qualified pension plan expense on MI’s pension plan that was previously recorded as an unallocated Corporate expense. In 2004, we recorded approximately $21.8 million of pension expense related to BWXT (substantially all of our Government Operations segment) in unallocated Corporate. In addition, effective January 31, 2005, the B&W portion of MI’s qualified pension plan was spun off into a new plan sponsored by B&W. As a result, we no longer allocated pension expense associated with B&W’s portion of the pension plan to unallocated Corporate. In 2004, pension expense associated with the spun off plan was recorded in unallocated Corporate.
Other Income Statement Items
Interest income increased by $15.5 million to $21.1 million, primarily due to an increase in investments.
Interest expense decreased by $4.2 million, primarily due to a reduction in interest expense attributable to interest on potential tax deficiencies.
Provision for Income Taxes
For the year ended December 31, 2005, we reversed $50.4 million of our federal deferred tax asset valuation allowance (“Valuation Allowance Adjustment”), eliminating our MI federal deferred tax asset valuation allowance associated with our minimum pension liability discussed below. SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”), provides that a valuation allowance must be established for deferred tax assets when it is more likely than not that the assets will not be realized. SFAS No. 109 also provides that all positive and negative evidence must be evaluated in determining the need for a valuation allowance. In the quarter ended June 30, 2005, our BWXT subsidiary received contract extensions on its management contracts for the Y-12 and Pantex sites from the National Nuclear Security Administration. In addition, we evaluated our forecast of pre-tax income at MI on a going-concern basis, and based on cumulative positive pre-tax income at MI in the prior three years, including pre-tax income for 2005, and a forecast of positive pre-tax income in the future, we determined that we no longer required a federal deferred tax asset valuation allowance. This federal deferred tax asset valuation allowance was originally recorded in 2002 as an adjustment to Other Comprehensive Income at MI generated by an increase to MI’s Minimum Pension Liability. The gross deferred tax asset on this item was reduced substantially based on the spin-off of the B&W portion of MI’s pension plan to B&W. Under the guidelines of SFAS No. 109, we reversed the remaining component of this federal valuation allowance by a credit to our provision for income taxes totaling approximately $50.4 million.
Substantially as a result of the Valuation Allowance Adjustment discussed above, the provision for income taxes decreased $31.2 million to $8.8 million, while income before provision for income taxes increased $101.9 million to $206.7 million. Our effective tax rate for the year ended December 31, 2005 was approximately 4.3%.
MII is a Panamanian corporation that has earned all of its income outside of Panama. Under Panamanian tax law, MII is not subject to income tax in Panama on income earned outside of Panama.
We have provided for income taxes based on the tax laws and rates in the countries in which we conduct our operations. MII and its subsidiaries operate in the U.S. taxing jurisdiction and various other taxing jurisdictions around the world. Each of these jurisdictions has a regime of taxation that varies from the others. The taxation
regimes vary not only with respect to nominal rates, but also with respect to the allowability of deductions, credits and other benefits and tax bases (for example, revenue versus income). These variances, along with variances in our mix of income from these jurisdictions, are responsible for shifts in our effective tax rate.
Income (loss) from continuing operations before provision for income taxes, provision for income taxes and effective tax rates for MII’s major subsidiaries are as follows:
MI is subject to U.S. federal income tax at a rate of 35%. The effective tax rate of MI was primarily affected by the B&W Chapter 11 settlement adjustment, which has generated little or no associated U.S. income tax effect and applicable state income taxes on its profitable BWXT subsidiary. In addition, the 2005 tax rate was affected by the Valuation Allowance Adjustment discussed above.
JRMH was subject to U.S. income tax at a rate of 35%. No current U.S. income tax is payable by JRMH due to its current loss. JRMH’s valuation allowance for the realization of deferred tax assets had been adjusted in accordance with SFAS No. 109. JRMH’s provision for income taxes was primarily associated with its operations performed outside of the U.S., which had no relationship to its loss from continuing operations before provision for income taxes.
The American Jobs Creation Act of 2004 introduced a special one-time dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer, provided several criteria are met. The repatriation and reinvestment plan we adopted is part of B&W, which was not consolidated with our results in 2005. We also reviewed the other provisions of the Jobs Creation Act, including the provisions which permitted a U.S. taxpayer to claim in its 2005 tax filing a deduction from taxable income attributable to its domestic production and manufacturing activities. Various domestic activities that we perform were considered production and manufacturing activities, as defined in the Jobs Creation Act.
See Note 4 to our consolidated financial statements included in this report for further information on taxes.
EFFECTS OF INFLATION AND CHANGING PRICES
Our financial statements are prepared in accordance with generally accepted accounting principles in the United States, using historical U.S. dollar accounting (“historical cost”). Statements based on historical cost, however, do not adequately reflect the cumulative effect of increasing costs and changes in the purchasing power of the dollar, especially during times of significant and continued inflation.
In order to minimize the negative impact of inflation on our operations, we attempt to cover the increased cost of anticipated changes in labor, material and service costs, either through an estimate of those changes, which we reflect in the original price, or through price escalation clauses in our contracts.
LIQUIDITY AND CAPITAL RESOURCES
JRM
On June 6, 2006, JRM completed a cash tender offer for all its outstanding 11% senior secured notes due 2013 (“JRM Secured Notes”). The tender offer consideration was based on a fixed-spread over specified U.S. Treasury
securities, which equated to an offer price of approximately 119% of the principal amount of the notes. JRM used cash on hand to purchase the entire $200 million in aggregate principal amount of the JRM Secured Notes outstanding for approximately $249.0 million, including accrued interest of approximately $10.9 million. As a result of this early retirement of debt, we recognized $49.0 million of expense during the year ended December 31, 2006.
On June 6, 2006, JRM entered into a new $500 million senior secured credit facility with a syndicate of lenders (the “JRM Credit Facility”). The JRM Credit Facility comprises a five-year, $400 million revolving credit (all of which may be used for the issuance of letters of credit and $250 million of which may be used for revolver borrowings), which matures on June 6, 2011, and a six-year, $100 million synthetic letter of credit subfacility, which matures on June 6, 2012. The proceeds of the JRM Credit Facility are available for working capital needs and other general corporate purposes of JRM and its subsidiaries.
JRM’s obligations under the JRM Credit Facility are unconditionally guaranteed by substantially all of JRM’s wholly owned subsidiaries and secured by liens on substantially all of JRM’s and these subsidiaries’ assets (other than cash, cash equivalents, equipment and certain foreign assets), including their major marine vessels. JRM is permitted to prepay amounts outstanding under the JRM Credit Facility at any time without penalty. Other than customary mandatory prepayments on certain contingent events, the JRM Credit Facility requires only interest payments on a quarterly basis until maturity. Loans outstanding under the revolving credit subfacility bear interest at either the Eurodollar rate plus a margin ranging from 2.25% to 2.50% per annum or the base rate plus a margin ranging from 1.25% to 2.25% per annum. The applicable margin for revolving loans varies depending on JRM’s credit ratings. JRM is charged a commitment fee on the unused portions of the $400 million revolving credit subfacility, and that fee varies between 0.375% and 0.50% per annum depending on JRM’s credit ratings. Additionally, JRM is charged a letter of credit fee of between 2.25% and 2.50% per annum with respect to the amount of each letter of credit issued under the revolving credit subfacility. JRM is also charged a fee of 2.60% per annum on the full amount of the synthetic letter of credit subfacility, regardless of whether the subfacility is drawn upon. An additional 0.125% annual fee is charged on the amount of each letter of credit issued under both subfacilities.
The JRM Credit Facility contains customary financial covenants relating to leverage and interest coverage and includes covenants that restrict, among other things, debt incurrence, liens, investments, acquisitions, asset dispositions, dividends, prepayments of subordinated debt, mergers, transactions with affiliates and capital expenditures. JRM was in compliance with these covenants at December 31, 2006.
On February 23, 2006, JRM cancelled its separate $25 million letter of credit facility entered into on August 25, 2004.
At December 31, 2006, JRM had no borrowings outstanding, and letters of credit issued on the JRM Credit Facility totaled $250.2 million. In addition, JRM had $129.8 million in outstanding unsecured letters of credit under separate arrangements with financial institutions at December 31, 2006.
On December 22, 2005, JRM, as guarantor, and its subsidiary, J. Ray McDermott Middle East, Inc., entered into a $105.2 million unsecured performance guarantee issuance facility with a syndicate of commercial banking institutions. The outstanding amount under this facility is included in the $129.8 million outstanding referenced above. This facility provides credit support for bank guarantees issued in favor of three projects awarded to JRM. The term of this facility is for the duration of these projects, and the average commission rate is less than 4.50% on an annualized basis.
In April 2006, JRM completed the sale of a Mexican subsidiary, Talleres Navales del Golfo, S.A. de C.V., and received approximately $19.5 million in proceeds.
Based on JRM’s liquidity position, we believe JRM has sufficient cash and letter of credit and borrowing capacity to fund its operating requirements for at least the next 12 months.
BWXT
On December 9, 2003, BWXT entered into a three-year, unsecured, $125 million credit facility (the “BWXT Credit Facility”). The BWXT Credit Facility may be increased to a total of $150 million at our discretion, and in fact, it was increased to $135 million in January 2004. In March 2005, the maturity date was extended to March 18, 2010, and on November 7, 2005, BWXT and its lenders amended the BWXT Credit Facility to, among other things, permit the full amount of the facility to be used for loans.
The BWXT Credit Facility is a revolving credit agreement providing for borrowings and issuances of letters of credit in an aggregate amount of up to $135 million. The BWXT Credit Facility requires BWXT to comply with various financial and nonfinancial covenants and reporting requirements. The financial covenants require BWXT to maintain a maximum leverage ratio, a minimum fixed charge coverage ratio and a maximum debt to capitalization ratio. BWXT was in compliance with these covenants at December 31, 2006. The interest rate at December 31, 2006 was 8.75%. BWXT is charged an annual commitment fee of 0.375%, which is payable quarterly. Additionally, BWXT is charged a letter of credit fee of between 1.50% and 2.50% per annum with respect to the amount of each letter of credit issued. An additional 0.125% per annum fee is charged on the amount of each letter of credit issued. At December 31, 2006, BWXT had no borrowings outstanding, and letters of credit outstanding under the facility totaled $50.8 million.
Based on BWXT’s liquidity position, we believe BWXT has sufficient cash and letter of credit and borrowing capacity to fund its operating requirements for at least the next 12 months.
B&W
On February 22, 2006, B&W entered into a $650 million senior secured credit facility with a syndicate of lenders (the “B&W Facility”) to replace B&W’s debtor-in-possession credit facility, which was terminated when B&W’s Chapter 11 proceedings were concluded. The B&W Facility includes a five-year, $200 million revolving credit subfacility (the entire availability of which may be used for the issuance of letters of credit or working capital requirements), a six-year, $200 million letter of credit subfacility and a commitment by certain of the lenders to loan B&W up to $250 million in term debt to refinance the $250 million promissory note due to a trust for the benefit of asbestos personal injury claimants under the B&W Chapter 11 plan of reorganization. The term loan could only be used by B&W in a single draw, and the commitment of the lenders to make this loan was set to expire on December 1, 2006.
B&W’s obligations under the B&W Facility are unconditionally guaranteed by all of B&W’s domestic subsidiaries and secured by liens on substantially all of B&W’s and these subsidiaries’ assets, excluding cash and cash equivalents.
Loans outstanding under the revolving credit subfacility bear interest at either the Eurodollar rate plus a margin ranging from 2.75% and 3.25% per annum or the base rate plus a margin ranging from 1.75% to 2.25% per annum. The applicable margin for revolving loans varies depending on B&W’s credit ratings. The applicable margin for the $250 million term loan, which is a Eurodollar rate loan, is 3.0% per annum. The interest rate for the term loan at December 31, 2006 was 8.36%. B&W is charged a commitment fee on the unused portion of the revolving credit subfacility, and that fee varies between 0.25% and 0.50% per annum depending on B&W’s credit ratings. Additionally, B&W is charged a letter of credit fee of between 2.75% and 3.25% per annum with respect to the amount of each letter of credit issued under the revolving credit subfacility. B&W is also charged a fee of 2.85% per annum on the full amount of the synthetic letter of credit subfacility, regardless of whether the subfacility is drawn upon. An additional 0.125% per annum fee is charged on the amount of each letter of credit issued under each subfacility.
If B&W’s leverage ratio is above 2.0 to 1.0, B&W must offer to repay the term loan once each year in an amount equal to the lesser of $50 million and 50% of its excess cash flow. B&W must also prepay the term loan with the proceeds of certain asset sales, casualties, condemnations and debt issuances. Other than these mandatory prepayments, the B&W Facility only requires interest payments for the revolving credit subfacility and the letter of credit subfacility on a quarterly basis until maturity, which is February 22, 2011 and February 22, 2012, respectively. In addition to quarterly interest payments, the term loan requires principal payments, based on 1% of the original principal amount, payable quarterly until maturity, which is February 22, 2012. B&W may prepay amounts outstanding under the B&W Facility at any time without penalty.
The B&W Facility contains customary financial covenants, including maintenance of a maximum leverage ratio and a minimum interest coverage ratio, and covenants that, among other things, restrict B&W’s ability to incur debt, create liens, make investments and acquisitions, sell assets, pay dividends, prepay subordinated debt, merge with other entities, engage in transactions with affiliates and make capital expenditures. The B&W Facility also contains customary events of default. B&W was in compliance with these covenants at December 31, 2006.
On November 30, 2006, B&W drew down $250 million on its term loan under the B&W Facility and completed its obligation to pay the $250 million promissory note to the trust on December 1, 2006. This promissory note was recorded in Accrued Cost of The Babcock & Wilcox Company Bankruptcy Settlement on our consolidated balance sheets at its fair value of approximately $245.3 million, and therefore, this retirement resulted in the recognition of approximately $4.7 million of expense. The term loan debt under the B&W Facility is scheduled to mature on February 22, 2012. While not due to mature until 2012, B&W intends to repay the term loan debt during 2007, and therefore, the $250 million outstanding has been classified as current on our consolidated balance sheets included in this report.
Also in connection with B&W’s Chapter 11 proceedings, B&W paid $350 million to the trust on February 22, 2006, prior to B&W’s reconsolidation. During December 2006, MI paid an additional $355 million to the trust. All financial obligations under the B&W Chapter 11 plan of reorganization were satisfied as of December 31, 2006. As a result of these payments made during the year ended December 31, 2006 by MI and B&W, a significant tax loss was generated by the MI group. MI plans to file a claim in 2007 to carry this loss back to offset a portion of its taxable income in the prior ten-year period. MI expects to receive a tax refund as a result of this carryback claim of approximately $270 million. For additional information concerning the settlement of B&W’s Chapter 11 proceedings, see Note 20 to our consolidated financial statements included in this report.
As of December 31, 2006, B&W had outstanding borrowings of $250 million under its term loan feature of the B&W Facility, and letters of credit issued on the B&W Facility totaled $229.8 million.
Based on B&W’s liquidity position, we believe B&W has sufficient cash and letter of credit and borrowing capacity to fund its operating requirements for at least the next 12 months.
OTHER
One of B&W’s Canadian subsidiaries has received notice of a possible warranty claim on one of its projects on a contract executed in 1998. This project included a limited-term performance bond totaling approximately $140 million, for which MII entered into an indemnity arrangement with the surety underwriters. At this time, we are continuing to analyze the facts and circumstances surrounding this issue. It is possible that B&W’s subsidiary may incur warranty costs in excess of amounts provided for as of December 31, 2006. It is also possible that a claim could be initiated by the B&W subsidiary’s customer against the surety underwriter should certain events occur. If such a claim were successful, the surety could seek to recover from B&W’s subsidiary the costs incurred in satisfying the customer claim. If the surety should seek recovery from B&W’s subsidiary, we believe that B&W’s subsidiary would have adequate liquidity to satisfy its obligations. However, the ultimate resolution of this possible claim is uncertain, and an adverse outcome could have a material adverse impact on our consolidated financial position, results of operations and cash flows.
We are currently exploring growth strategies across our segments through acquisitions to expand and complement our existing businesses. As we pursue these opportunities, we expect they would be funded by cash on hand, external financing or both.
At December 31, 2006, we had total restricted cash and cash equivalents of $106.7 million. The restricted cash and cash equivalents include the following: $17.6 million, which is required to meet reinsurance reserve requirements of our captive insurance companies and $89.1 million, which is held in restricted foreign accounts.
At December 31, 2006 and December 31, 2005, our balance in cash and cash equivalents on our consolidated balance sheets included approximately $18.0 million and $7.3 million, respectively, in adjustments for bank overdrafts, with a corresponding increase in accounts payable for these overdrafts.
Our working capital, excluding restricted cash and cash equivalents, decreased by approximately $527.7 million from $81.9 million at December 31, 2005 to a negative $445.8 million at December 31, 2006. This decrease is primarily attributable to the $355 million payment to the trust under the B&W Chapter 11 plan of reorganization using available cash and cash equivalents and the current obligation of $250 million resulting from the use of the term loan feature of the B&W Facility. These decreases were partially offset by favorable cash flows from operating activities.
Our net cash provided by operations was approximately $228.1 million for the year ended December 31, 2006, compared to approximately $254.9 million for the year ended December 31, 2005. This decrease was primarily attributable to our payments made in connection with the B&W Chapter 11 plan of reorganization and recognition of an income tax receivable, partially offset by favorable cash flows from our contracts in progress, accounts payable and accrued liabilities.
Our net cash provided by (used in) investing activities changed by approximately $801.2 million to cash provided by investing activities totaling $310.4 million for the year ended December 31, 2006, compared to cash used in investing activities totaling $490.8 million for the year ended December 31, 2005. This change was primarily attributable to the reconsolidation of B&W and the sale/maturity of available-for-sale securities.
Our net cash provided by (used in) financing activities changed by approximately $47.9 million to cash provided by financing activities totaling $43.7 million for the year ended December 31, 2006, compared to cash used in financing activities totaling $4.2 million for the year ended December 31, 2005. This change was primarily attributable to the issuance of debt under the B&W Facility during 2006, partially offset by the early retirement of the JRM secured notes.
At December 31, 2006, we had investments with a fair value of $294.1 million. Our investment portfolio consists primarily of investments in government obligations and other highly liquid money market instruments. As of December 31, 2006, we had pledged approximately $36 million fair value of these investments to secure a letter of credit in connection with certain reinsurance agreements.
CONTRACTUAL OBLIGATIONS
Our cash requirements as of December 31, 2006 under current contractual obligations are as follows:
We have interest payments on our long-term debt obligations above as follows: less than one year, $6.3 million; one to three years, $1.1 million; three to five years, $0.5 million; and after five years, $0.1 million, for a total of $8.0 million. These obligations are based on the debt outstanding at December 31, 2006 and the stated interest rates. In addition, we expect to contribute approximately $99.1 million to our domestic pension plans, which includes approximately $58.0 million for B&W, $35.8 million for BWXT and $5.3 million for JRM pension plans, respectively, and $12.1 million to our other postretirement benefit plans in 2007.
Our contingent commitments under letters of credit currently outstanding expire as follows:
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our exposure to market risk from changes in interest rates relates primarily to our cash equivalents and our investment portfolio, which is primarily comprised of investments in U.S. Government obligations and highly liquid money market instruments denominated in U.S. dollars. We are averse to principal loss and ensure the safety and preservation of our invested funds by limiting default risk, market risk and reinvestment risk. All our investments in debt securities are classified as available-for-sale.
We have exposure to changes in interest rates on the JRM Credit Facility, the BWXT Credit Facility and the B&W Facility (see Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources”). At December 31, 2006, we had no outstanding borrowings under the JRM Credit Facility and the BWXT Credit Facility, and we had $250 million outstanding under the B&W Facility. We have no material future earnings or cash flow exposures from changes in interest rates on our other long-term debt obligations, as substantially all of these obligations have fixed interest rates.
We have operations in many foreign locations, and, as a result, our financial results could be significantly affected by factors such as changes in foreign currency exchange rates or weak economic conditions in those foreign markets. In order to manage the risks associated with foreign currency exchange rate fluctuations, we attempt to hedge those risks with foreign currency derivative instruments. Historically, we have hedged those risks with foreign currency forward contracts. We have recently hedged some of those risks with foreign currency option contracts. We do not enter into speculative derivative positions.
Interest Rate Sensitivity
The following tables provide information about our financial instruments that are sensitive to changes in interest rates. The tables present principal cash flows and related weighted-average interest rates by expected maturity dates.
Principal Amount by Expected Maturity
(In thousands)
At December 31, 2006:
At December 31, 2005:
Exchange Rate Sensitivity
The following table provides information about our foreign currency forward contracts outstanding at December 31, 2006 and presents such information in U.S. dollar equivalents. The table presents notional amounts and related weighted-average exchange rates by expected (contractual) maturity dates and constitutes a forward-looking statement. These notional amounts generally are used to calculate the contractual payments to be exchanged under the contract.
Forward Contracts to Purchase Foreign Currencies in U.S. Dollars (in thousands):
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of McDermott International, Inc.:
We have audited the accompanying consolidated balance sheet of McDermott International, Inc. and subsidiaries (the “Company”) as of December 31, 2006, and the related consolidated statements of income, comprehensive income, stockholders’ equity (deficit), and cash flows for the year then ended. Our audit also included the 2006 financial statement schedules listed in the Index at Item 15(2). These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audit. The consolidated financial statements and financial statement schedules of the Company for the years ended December 31, 2005 and 2004, before the effects of the retrospective adjustments for the discontinued operations discussed in Note 2 and the three-for-two common stock split discussed in Note 8 to the consolidated financial statements, were audited by other auditors whose report, dated February 28, 2006, expressed an unqualified opinion on those statements and schedules.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such 2006 consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2006, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, such 2006 financial statement schedules, when considered in relation to the basic consolidated financial statements as a whole, present fairly, in all material respects, the financial information set forth therein.
As discussed in Notes 1 and 20 to the consolidated financial statements, on February 22, 2000, The Babcock & Wilcox Company (“B&W”), a wholly owned subsidiary of the Company, filed a voluntary petition with the U.S. Bankruptcy Court to reorganize under Chapter 11 of the U.S. Bankruptcy Code. On January 17, 2006 the United States District Court for the Eastern District of Louisiana issued an order confirming B&W’s Chapter 11 Joint Plan of Reorganization and associated settlement agreement and on February 22, 2006 B&W emerged from Chapter 11. B&W and its subsidiaries’ results of operations have been included in the consolidated financial statements of the Company effective February 22, 2006. As further discussed in Note 1 and 20, due to the Chapter 11 proceedings, B&W and its subsidiaries’ results of operations were not included in the consolidated financial statements of the Company from February 22, 2000 through February 22, 2006.
We have also audited the retrospective adjustments to the 2005 and 2004 consolidated financial statements for the operations discontinued in 2006 discussed in Note 2 and the three-for-two common stock split in 2006 discussed in Note 8 to the consolidated financial statements. Our procedures included (1) obtaining the Company’s underlying accounting analysis from management of the retrospective adjustments for discontinued operations and comparing the retrospectively adjusted amounts per the 2005 and 2004 financial statements to such analysis, (2) comparing previously reported amounts to the previously issued financial statements for such years, (3) testing the mathematical accuracy of the accounting analysis, (4) on a test basis, comparing the adjustments to retrospectively adjust the financial statements for discontinued operations to independent supporting documentation, (5) comparing the amounts shown in the earnings per share disclosures for 2005 and 2004 to the Company’s underlying accounting analysis obtained from management, (6) comparing the previously reported shares outstanding and income statement amounts per the Company’s accounting analysis to the previously issued financial statements, and (7) recalculating the additional shares to give effect to the stock split and testing the mathematical accuracy of the underlying analysis. In our opinion, such retrospective adjustments are appropriate and have been properly applied. However, we were not engaged to audit, review or apply any procedures to the 2005 and 2004 consolidated financial statements and financial statement schedules of the Company other than with respect to the retrospective
adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2005 and 2004 consolidated financial statements and financial statement schedules taken as a whole.
As discussed in Note 1 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standard (“SFAS”) No. 123(R), “Share-Based Payment” as of January 1, 2006 and SFAS No. 158, “Employee Accounting for Defined Benefit Pension and Other Postretirement Plans” as of December 31, 2006.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Houston, Texas
March 1, 2007
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of McDermott International, Inc.:
In our opinion, the consolidated balance sheet as of December 31, 2005 and the related consolidated statements of income, comprehensive income, shareholders’ deficit and cash flows for each of two years in the period ended December 31, 2005, before the effects of the adjustments to retrospectively reflect the discontinued operations described in Note 2 and the adjustments to retrospectively reflect the three-for-two stock split described in Note 8, present fairly, in all material respects, the financial position of McDermott International, Inc. and its subsidiaries (the “Company”) at December 31, 2005, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America (the 2005 and 2004 consolidated financial statements before the effects of the adjustments discussed in Notes 2 and 8 are not presented herein). In addition, in our opinion, the financial statement schedules for each of the two years in the period ended December 31, 2005 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements referred to above. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits, before the effects of the adjustments described above, of these statements in accordance with the standards of the Public Company Accounting Oversight Board (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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the discontinued operations described in Note 2 or the adjustments to retrospectively reflect the three-for-two stock split described in Note 8 and accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by other auditors.
As discussed in Notes 1, 20 and 22 to the consolidated financial statements included in the 2005 Form 10-K (not separately presented herein), on February 22, 2000, The Babcock & Wilcox Company (“B&W”), a wholly owned subsidiary of the Company, filed a voluntary petition with the U.S. Bankruptcy Court to reorganize under Chapter 11 of the U.S. Bankruptcy Code. On January 17, 2006 the United States District Court for the Eastern District of Louisiana issued an order confirming B&W’s Chapter 11 Joint Plan of Reorganization and associated settlement agreement and on February 22, 2006, B&W’s Plan and associated settlement agreement became effective and B&W emerged from Chapter 11.
PricewaterhouseCoopers LLP
Houston, Texas
February 28, 2006
McDERMOTT INTERNATIONAL, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
See accompanying notes to consolidated financial statements.
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
See accompanying notes to consolidated financial statements.
McDERMOTT INTERNATIONAL, INC.
CONSOLIDATED STATEMENTS OF INCOME
See accompanying notes to consolidated financial statements.
McDERMOTT INTERNATIONAL, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See accompanying notes to consolidated financial statements.
McDERMOTT INTERNATIONAL, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
See accompanying notes to consolidated financial statements.
McDERMOTT INTERNATIONAL, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
McDERMOTT INTERNATIONAL, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2006
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
We have presented our consolidated financial statements in U.S. Dollars in accordance with accounting principles generally accepted in the United States (“GAAP”). These consolidated financial statements include the accounts of McDermott International, Inc. and its subsidiaries and controlled joint ventures consistent with Financial Accounting Standards Board (“FASB”) Interpretation No. 46(R), “Consolidation of Variable Interest Entities (revised December 2003).” We use the equity method to account for investments in joint ventures and other entities we do not control, but over which we have significant influence. We have eliminated all significant intercompany transactions and accounts. We present the notes to our consolidated financial statements on the basis of continuing operations, unless otherwise stated.
McDermott International, Inc. (“MII”), incorporated under the laws of the Republic of Panama in 1959, is an engineering and construction company with specialty manufacturing and service capabilities and is the parent company of the McDermott group of companies, which includes:
•
J. Ray McDermott, S.A., a Panamanian subsidiary of MII (“JRMSA”), and its consolidated subsidiaries;
•
McDermott Holdings, Inc., a Delaware subsidiary of MII (“MHI”), and its consolidated subsidiaries;
•
McDermott Incorporated, a Delaware subsidiary of MHI (“MI”), and its consolidated subsidiaries;
•
Babcock & Wilcox Companies, a Delaware subsidiary of MI (“B&WC”);
•
BWX Technologies, Inc., a Delaware subsidiary of B&WC (“BWXT”), and its consolidated subsidiaries; and
•
The Babcock & Wilcox Company, a Delaware subsidiary of B&WC (“B&W”), and its consolidated subsidiaries.
JRMSA and its subsidiaries and JRMH and its subsidiaries are hereafter collectively referred to as JRM.
On February 22, 2006, B&W and three of its subsidiaries exited from the Chapter 11 Bankruptcy proceedings. Due to the Chapter 11 proceedings, we did not consolidate B&W’s and its subsidiaries’ results of operations in our consolidated financial statements from February 22, 2000 through February 22, 2006. See Note 20 for information on B&W and its subsidiaries.
Use of Estimates
We use estimates and assumptions to prepare our financial statements in conformity with GAAP. These estimates and assumptions affect the amounts we report in our financial statements and accompanying notes. Our actual results could differ from those estimates. Variances could result in a material effect on our results of operations and financial position in future periods.
Earnings Per Share
We have computed earnings per common share on the basis of the weighted average number of common shares, and, where dilutive, common share equivalents, outstanding during the indicated periods.
Investments
Our investments, primarily government obligations and other highly liquid money market instruments, are classified as available-for-sale and are carried at fair value, with the unrealized gains and losses, net of tax, reported as a component of accumulated other comprehensive loss. We classify investments available for current operations in the balance sheet as current assets, while we classify investments held for long-term purposes as noncurrent assets. We adjust the amortized cost of debt securities for amortization of premiums and accretion of discounts to maturity. That amortization is included in interest income. We include realized gains and losses on our investments in other income (expense). The cost of securities sold is based on the specific identification method. We include interest on securities in interest income.
Foreign Currency Translation
We translate assets and liabilities of our foreign operations, other than operations in highly inflationary economies, into U.S. Dollars at current exchange rates, and we translate income statement items at average exchange rates for the periods presented. We record adjustments resulting from the translation of foreign currency financial statements as a component of accumulated other comprehensive loss. We report foreign currency transaction gains and losses in income. We have included in other income (expense) transaction gains (losses) of ($6.3) million, $2.1 million and ($3.8) million for the years ended December 31, 2006, 2005 and 2004, respectively.
Contracts and Revenue Recognition
We generally recognize contract revenues and related costs on a percentage-of-completion method for individual contracts or combinations of contracts based on work performed, man hours, or a cost-to-cost method, as applicable to the product or activity involved. Some of our contracts contain a risk-and-reward element, whereby a portion of total compensation is tied to the overall performance of several companies working under alliance arrangements. We include revenues and related costs so recorded, plus accumulated contract costs that exceed amounts invoiced to customers under the terms of the contracts, in contracts in progress. We include in advance billings on contracts billings that exceed accumulated contract costs and revenues and costs recognized under the percentage-of-completion method. Most long-term contracts contain provisions for progress payments. We expect to invoice customers for all unbilled revenues. We review contract price and cost estimates periodically as the work progresses and reflect adjustments proportionate to the percentage-of-completion in income in the period when those estimates are revised. For all contracts, if a current estimate of total contract cost indicates a loss on a contract, the projected loss is recognized in full when determined.
For contracts as to which we are unable to estimate the final profitability except to assure that no loss will ultimately be incurred, we recognize equal amounts of revenue and cost until the final results can be estimated more precisely. For these deferred profit recognition contracts, we recognize revenue and cost equally and only recognize gross margin when probable and reasonably estimable, which we generally determined to be when the contract is approximately 70% complete. We treat long-term construction contracts that contain such a level of risk and uncertainty that estimation of the final outcome is impractical except to assure that no loss will be incurred, as deferred profit recognition contracts.
Our policy is to account for fixed-price contracts under the completed-contract method if we believe we are unable to reasonably forecast cost to complete at start-up. Under the completed-contract method, income is recognized only when a contract is completed or substantially complete.
Variations from estimated contract performance could result in material adjustments to operating results for any fiscal quarter or year. We include claims for extra work or changes in scope of work to the extent of costs incurred in contract revenues when we believe collection is probable.
The following amounts represent retainages on contracts:
We have included in accounts receivable - trade retainages expected to be collected in 2007. Retainages expected to be collected after one year are included in other assets. Of the long-term retainages at December 31, 2006, we anticipate collecting $42.3 million in 2008, $17.3 million in 2009, $7.4 million in 2010 and $0.6 million in 2011.
Comprehensive Loss
The components of accumulated other comprehensive loss included in stockholders’ equity (deficit) are as follows:
Warranty Expense
We accrue estimated expense to satisfy contractual warranty requirements, primarily of our Government Operations and Power Generation Systems segments, when we recognize the associated revenue on the related contracts. We include warranty costs associated with our Offshore Oil and Gas Construction segment as a component of our total contract cost estimate to satisfy contractual requirements. In addition, we make specific provisions where we expect the actual warranty costs to significantly exceed the accrued estimates. Such provisions could have a material effect on our consolidated financial position, results of operations and cash flows.
The following summarizes the changes in the carrying amount of accrued warranty:
Asset Retirement Obligations and Environmental Clean-up Costs
We accrue for future decommissioning of our nuclear facilities that will permit the release of these facilities to unrestricted use at the end of each facility’s life, which is a requirement of our licenses from the Nuclear Regulatory Commission. Effective January 1, 2003, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), requiring us to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When we initially record such a liability, we capitalize a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of a liability, we will settle the obligation for its recorded amount or incur a gain or loss. SFAS No. 143 applies to
environmental liabilities associated with assets that we currently operate and are obligated to remove from service. For environmental liabilities associated with assets that we no longer operate, we have accrued amounts based on the estimated costs of clean-up activities, net of any cost-sharing arrangements. We adjust the estimated costs as further information develops or circumstances change. An exception to this accounting treatment relates to the work we perform for one facility, for which the U.S. Government is obligated to pay all the decommissioning costs.
Substantially all our asset retirement obligations relate to the remediation of our nuclear analytical laboratory in our Government Operations segment. The following table reflects our asset retirement obligations:
Research and Development
Research and development activities are related to development and improvement of new and existing products and equipment and conceptual and engineering evaluation for translation into practical applications. We charge to operations the costs of research and development not performed on specific contracts as we incur them. These expenses totaled approximately $18.7 million, $3.3 million and $4.6 million in the years ended December 31, 2006, 2005 and 2004, respectively. In addition, our customers paid for expenditures we made on research and development activities of approximately $26.5 million, $30.8 million and $25.1 million in the years ended December 31, 2006, 2005 and 2004, respectively.
Inventories
We carry our inventories (principally in B&W, which was not consolidated at December 31, 2005) at the lower of cost or market. We determine cost principally on the first-in-first-out basis, except for certain materials inventories at B&W, for which we use the last-in-first-out method. We determined the cost of approximately 17% of our total inventories using the LIFO method at December 31, 2006, and the total LIFO reserve at December 31, 2006 was approximately $5.6 million. Inventories are summarized below:
Property, Plant and Equipment
We carry our property, plant and equipment at depreciated cost, reduced by provisions to recognize economic impairment when we determine impairment has occurred.
Except for major marine vessels, we depreciate our property, plant and equipment using the straight-line method, over estimated economic useful lives of eight to 40 years for buildings and two to 28 years for machinery and equipment. We depreciate major marine vessels using the units-of-production method based on the utilization of each vessel. Our depreciation expense calculated under the units-of-production method may be less than, equal to, or greater than depreciation expense calculated under the straight-line method in any period. The annual depreciation based on utilization of each vessel will not be less than the greater of 25% of annual straight-line depreciation or 50% of cumulative straight-line depreciation. Our depreciation expense was $60.5 million, $43.1 million and $36.7 million for the years ended December 31, 2006, 2005 and 2004, respectively.
We expense the costs of maintenance, repairs and renewals that do not materially prolong the useful life of an asset as we incur them, except for drydocking costs. Through December 31, 2006, we accrued estimated drydocking costs, including labor, raw materials, equipment and regulatory fees, for our marine fleet over the period of time between drydockings, which is generally three to five years. We accrued drydocking costs in advance of the anticipated future drydocking,
commonly known as the accrue-in-advance method. Actual drydocking costs were charged against the liability when incurred, and any differences between actual costs and accrued costs were recognized over the remaining months of the drydocking cycle. Such differences could have a material effect on our consolidated financial position, results of operations and cash flows. Pursuant to FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” issued by the FASB during September 2006, we will change our accounting policy from the accrue-in-advance method to the deferral method, effective January 1, 2007, as discussed further in the New Accounting Pronouncements section of this Note 1.
Goodwill
On January 1, 2002, we adopted SFAS No. 142, “Goodwill and Other Intangible Assets.” Under SFAS No. 142, we no longer amortize goodwill to earnings, but instead we periodically test for impairment. The following summarizes the changes in the carrying amount of goodwill:
Other Intangible Assets
We amortize our intangible assets having definite useful lives. We have included our other intangible assets, consisting primarily of rights to use technology, in other assets, as follows:
The following summarizes the changes in the carrying amount of other intangible assets:
Other Non-Current Assets
We have included deferred debt issuance costs in other assets. We amortize deferred debt issuance cost as interest expense over the life of the related debt. Following are the changes in the carrying amount of these assets:
Capitalization of Interest Cost
We capitalize interest in accordance with SFAS No. 34, “Capitalization of Interest Cost.” We incurred total interest of $33.4 million, $33.7 million and $37.0 million in the years ended December 31, 2006, 2005 and 2004, respectively, of which we capitalized $3.1 million, $1.9 million and $1.0 million in the years ended December 31, 2006, 2005 and 2004, respectively. The total incurred interest for the year ended December 31, 2006 excludes the $5.7 million IRS interest expense adjustment. See Note 4 for additional information on the IRS interest expense adjustment.
Restricted Cash and Cash Equivalents
We record current cash as restricted when we are unable to freely use such cash and cash equivalents for our general operating purposes.
Our cash equivalents are highly liquid investments, with maturities of three months or less when we purchase them, which we do not hold as part of our investment portfolio.
Derivative Financial Instruments
Our worldwide operations give rise to exposure to market risks from changes in foreign exchange rates. We use derivative financial instruments to reduce the impact of changes in foreign exchange rates on our operating results. We use these instruments primarily to hedge our exposure associated with revenues or costs on our long-term contracts that are denominated in currencies other than our operating entities’ functional currencies. We record these contracts at fair value on our consolidated balance sheet. Depending on the hedge designation at the inception of the contract, the related gains and losses on these contracts are either deferred in stockholders’ equity (deficit) (as a component of accumulated other comprehensive loss) until the hedged item is recognized in earnings or offset against the change in fair value of the hedged firm commitment through earnings. The ineffective portion of a derivative’s change in fair value is immediately recognized in earnings. The gain or loss on a derivative financial instrument not designated as a hedging instrument is also immediately recognized in earnings. Gains and losses on derivative financial instruments that require immediate recognition are included as a component of other income (expense)-net in our consolidated statements of income.
Stock-Based Compensation
Effective January 1, 2006, we adopted the provisions of the revised SFAS No. 123, “Share-Based Payment” (“SFAS No. 123(R)”), on a modified prospective application basis. SFAS No. 123(R) eliminates the alternative permitted under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), to use Accounting Principles Board (“APB”) Opinion No. 25’s, “Accounting for Stock Issued to Employees” (“APB No. 25”), intrinsic value method of accounting, under which issuing stock options to employees generally did not result in recognition of compensation. Under the provisions of SFAS No. 123(R) and using the modified prospective application method, we recognize stock-based compensation based on the grant date fair value, net of an estimated forfeiture rate, for all share-based awards granted after December 31, 2005 and granted prior to, but not yet vested as of, December 31, 2005 on a straight-line basis over the requisite service periods of the awards, which is generally equivalent to the vesting term. Under the modified prospective application, the results of prior periods are not restated.
Prior to January 1, 2006, we accounted for our stock-based compensation plans using the intrinsic value method under APB No. 25 and related interpretations. Under APB No. 25, if the exercise price of the employee stock option equaled or exceeded the fair value of the underlying stock on the measurement date, no compensation expense was recognized. If the measurement date was later than the date of grant, compensation expense was recorded to the measurement date based on the quoted market price of the underlying stock at the end of each reporting period.
Under SFAS No. 123(R), the fair value of equity-classified awards, such as restricted stock and employee stock options, is determined on the date of grant and is not remeasured. Grant date fair values are determined using either the closing price of our common stock on the date of grant or an option-pricing model. We use the Black-Scholes option-pricing model (“Black-Scholes”) for measuring the fair value of stock options granted. The determination of the fair value of a share-based payment award on the date of grant using an option-pricing model requires the input of highly subjective assumptions, such as the expected life of the award and stock price volatility. For liability-classified awards, such as cash-settled performance units, fair values are determined at grant date and are remeasured at the end of each reporting period through the date of settlement.
SFAS No. 123(R) requires compensation expense to be recognized net of an estimate for forfeitures, such that compensation expense is recorded only for those awards expected to vest. We will review the estimate for forfeitures on a quarterly basis and record any adjustments deemed necessary for each reporting period. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation expense could be significantly different from what we have recorded in the current period.
Additionally, SFAS No. 123(R) amends SFAS No. 95, “Statement of Cash Flows,” to require reporting of excess tax benefits to be reported as a financing cash flow, rather than as a reduction of taxes paid. These excess tax benefits result from tax deductions in excess of the cumulative compensation expense recognized for options exercised and other equity-classified awards. Prior to the adoption of SFAS No. 123(R), we presented all tax benefits resulting from the exercise of stock options as operating cash flows in our consolidated statement of cash flows.
On March 29, 2005, the SEC issued Staff Accounting Bulletin (“SAB”) 107 to address certain issues related to SFAS No. 123(R). SAB 107 provides guidance on transition methods, valuation methods, income tax effects and other share-based payment topics, and we applied this guidance in our adoption of SFAS No. 123(R).
On November 10, 2005, the FASB issued FASB Staff Position (“FSP”) No. FAS No. 123(R)-3, “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards” (“FSP 123(R)-3”). FSP 123(R)-3 provides for an alternative transition method for establishing the beginning balance of the additional paid-in capital pool (“APIC pool”) related to the tax effects of employee share-based compensation, which is available to absorb tax deficiencies recognized subsequent to the adoption of SFAS No. 123(R). We have elected to adopt this alternative transition method, otherwise known as the “simplified method,” in establishing our beginning APIC pool at January 1, 2006.
See Note 9 for further discussion on stock-based compensation.
Stock options granted to employees of B&W during the pendency of B&W’s Chapter 11 proceedings were accounted for using the fair value method of SFAS No. 123, as B&W employees were not considered employees of MII for purposes of APB No. 25. In addition, for the years ended December 31, 2005 and 2004, our stock-based compensation cost included amounts related to stock options that required variable accounting.
New Accounting Standards
In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), to clarify the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”). FIN 48 is effective for fiscal years beginning after December 15, 2006. See Note 4 for additional information regarding the estimated impact of the adoption of FIN 48, effective January 1, 2007.
In September 2006, the FASB issued FSP AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” to prohibit the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. This FSP is effective for the first fiscal year beginning after December 15,
2006 and requires retrospective application for all financial statements presented. Through December 31, 2006, we used the accrue-in-advance method for the drydocking costs for our marine fleet. However, as of January 1, 2007, we will change our accounting policy from the accrue-in-advance method to the deferral method. We anticipate the cumulative effect of this change will result in an increase to assets and stockholders’ equity of approximately $40 million and $70 million, respectively, and a decrease to liabilities of approximately $30 million.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”), to require employers to recognize the funded status of their defined benefit plans in their balance sheets in the year in which the changes occur. SFAS No. 158 further requires employers to measure the funded status of their plans as of year-end. The requirement under SFAS No. 158 to recognize funded status in the balance sheet is effective for fiscal years ending after December 15, 2006, while the requirement to measure funded status concurrent with the fiscal year-end is effective for fiscal years ending after December 15, 2008. See Note 6 for additional information regarding the impact of the adoption of SFAS No. 158.
NOTE 2 -DISCONTINUED OPERATIONS
In April 2006, we completed the sale of our Mexican subsidiary, Talleres Navales del Golfo, S.A. de C.V. (“TNG”), a component of our Offshore Oil and Gas Construction segment. As a result of this sale, we received proceeds of $19.5 million and recorded a gain of $13.8 million. The gain is included in discontinued operations in our consolidated statements of income.
In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the consolidated statements of income for the years ended December 31, 2005 and 2004 have been restated for consistency to reflect TNG as a discontinued operation. Condensed financial information for our operations reported in discontinued operations is as follows:
We reported the assets and liabilities of TNG in our consolidated balance sheets as held for sale, which were primarily comprised of the following at December 31, 2005 (in thousands):
NOTE 3 - EQUITY METHOD INVESTMENTS
We have included in other assets investments in our worldwide joint ventures and other entities that we account for using the equity method of $52.6 million and $22.9 million at December 31, 2006 and 2005, respectively. The undistributed earnings of our equity method investees were $28.5 million and $8.3 million at December 31, 2006 and 2005, respectively.
Summarized below is combined balance sheet and income statement information, based on the most recent financial information, for investments in entities we accounted for using the equity method:
Revenues of equity method investees include $1,403.4 million, $1,660.5 million and $1,941.4 million of reimbursable costs recorded by limited liability companies in our Government Operations segment at December 31, 2006, 2005 and 2004, respectively. Our investment in equity method investees was less than our underlying equity in net assets of those investees based on stated ownership percentages by $0.6 million at December 31, 2006. These differences were primarily related to the timing of distribution of dividends and various adjustments under generally accepted accounting principles.
The provision for income taxes is based on the tax laws and rates in the countries in which our investees operate. There is no expected relationship between the provision for income taxes and income before provision for income taxes. The taxation regimes vary not only by their nominal rates, but also by the allowability of deductions, credits and other benefits. For some of our U.S. investees, U.S. income taxes are the responsibility of the respective owners.
Reconciliation of net income per combined income statement information to equity in income from investees per our consolidated statements of income is as follows:
Our transactions with unconsolidated affiliates include the following:
Our property, plant and equipment includes cost of $98.3 million and accumulated depreciation of $52.3 million at December 31, 2005 of marine equipment that was leased to an unconsolidated affiliate. During the year ended December 31, 2006, we disposed of our interest in this unconsolidated affiliate. Our accounts receivable - other includes a note receivable of $7.6 million due from this unconsolidated affiliate at December 31, 2005.
Effective January 1, 2006, we converted the accounting for our investment in Babcock & Wilcox Beijing Company, Ltd., a Chinese joint venture, from the cost method to the equity method. As a result of this conversion, we recorded adjustments to retained earnings of $7.0 million and to cumulative translation adjustment of $0.2 million. For the year ended December 31, 2006, we recognized $8.3 million of equity income related to this joint venture.
NOTE 4 - INCOME TAXES
We have provided for income taxes based on the tax laws and rates in the countries in which we conduct our operations. MII is a Panamanian corporation that has earned all of its income outside of Panama. As a result, we are not subject to income tax in Panama. We operate in the United States taxing jurisdiction and various other taxing jurisdictions around the world. Each of these jurisdictions has a regime of taxation that varies from the others. The taxation regimes vary not only with respect to nominal rate, but also with respect to the allowability of deductions, credits and other benefits. These variances, along with variances in our mix of income from these jurisdictions, contribute to shifts in our effective tax rate.
The reorganization of the MI and JRMH U.S. tax groups into a single consolidated U.S. tax group was completed on December 31, 2006. This reorganization provides us with administrative efficiencies, the opportunity to increase the flexibility of our financial structure and returns us to a more tax-efficient legal structure. Although we will continue to file a separate U.S. tax return for each U.S. tax group for the year ended December 31, 2006, the current earnings reflect both a current and deferred tax benefit for the JRMH U.S. tax group, as a result of the reorganization, via the release of the valuation against the JRMH deferred tax assets, as discussed below. Beginning January 1, 2007, the results of the former separate U.S. tax groups will be consolidated, and a single U.S. tax return filed.
Deferred income taxes reflect the net tax effects of temporary differences between the financial and tax bases of assets and liabilities. Significant components of deferred tax assets and liabilities as of December 31, 2006 and 2005 were as follows:
Income from continuing operations before provision for income taxes was as follows:
The provision for income taxes consisted of:
The following is a reconciliation of the U.S. statutory federal tax rate (35%) to the consolidated effective tax rate:
For the year ended December 31, 2006, we reversed $94.1 million of the deferred tax asset valuation allowance recorded against the JRMH deferred tax assets. SFAS No. 109 provides that a valuation allowance must be established for deferred tax assets when it is more likely than not that the assets will not be realized. SFAS No. 109 also provides that all positive and negative evidence must be evaluated in determining the need for a valuation allowance. As a result of the reorganization of our U.S. legal entities discussed above, we have reevaluated all the positive and negative evidence available to us and have determined that we no longer require a federal deferred tax asset valuation allowance. Under the guidelines of SFAS No. 109, we reversed the JRMH federal deferred tax asset valuation allowance through current period earnings by a credit to our provision for income taxes.
For the year ended December 31, 2005, we reversed our federal deferred tax asset valuation allowance totaling approximately $50.4 million, which eliminated our MI federal deferred tax asset valuation allowance associated with our minimum pension liability. This adjustment recorded for the year ended December 31, 2005 resulted in a benefit in our provision for income taxes of $50.4 million.
At December 31, 2006, we had a valuation allowance of $154.3 million for deferred tax assets, which we expect cannot be realized through carrybacks, future reversals of existing taxable temporary differences and our estimate of future taxable income. We believe that our remaining deferred tax assets are realizable through carrybacks, future reversals of existing taxable temporary differences and our estimate of future taxable income. Any changes to our estimated valuation allowance could be material to our consolidated financial statements.
We have foreign net operating loss carryforwards of approximately $43.2 million available to offset future taxable income in foreign jurisdictions. Approximately $1.9 million of the foreign net operating loss carryforwards is scheduled to expire in 2007 to 2010. The foreign net operating losses have a valuation allowance against the entire carryforward. We have domestic net operating loss carryforwards of approximately $342.3 million available to offset future taxable income in domestic jurisdictions, including $40.9 million of losses related to exercised stock options that will be reflected as an addition to capital in excess of par when utilized. The domestic net operating loss carryforwards are scheduled to expire in years 2009 to 2026. We have state net operating losses of $1,794.0 million available to offset future taxable income in various states. The state net operating loss carryforwards begin to expire in the year 2007. The state net operating losses have a valuation allowance against the entire carryforward.
We would be subject to withholding taxes on distributions of earnings from their U.S. subsidiaries and certain foreign subsidiaries. For the year ended December 31, 2006, the undistributed earnings of these subsidiaries was $414.7 million. Unrecognized deferred income tax liabilities, including withholding taxes, of approximately $167.6 million would be payable upon distribution of these earnings. We have not provided for any of these taxes, as we treat these earnings as permanently reinvested.
In the year ended December 31, 2006, MI reached a settlement in a tax dispute with United States and Canadian tax authorities, primarily related to transfer pricing matters, resulting in an adjustment to the tax liability and associated accrued interest established for the disputed item. This favorably impacted MI’s income from continuing operations before provision for income taxes and provision for income taxes by $13.2 million and $4.7 million, respectively. In addition, offsetting tax adjustments related to open years for MI federal and certain state tax jurisdictions were recorded in the year ended December 31, 2006, along with approximately $4.9 million of related interest expense. JRMH recorded a net provision for income taxes of approximately $9.0 million associated with potential U.S. income tax issues.
We reached settlements with the IRS concerning MI’s U.S. income tax liability through the fiscal year ended March 31, 1992 and JRM’s U.S. income tax liability for the stub year ended March 31, 1995, disposing of all U.S. federal income tax issues. The IRS has issued notices for MI for the fiscal years ended March 31, 1993 through December 31, 2003 and for JRM for the fiscal years ended March 31, 1996 through December 31, 2003 asserting deficiencies in the amount of taxes reported. We have reviewed the IRS positions and disagree with certain proposed adjustments relating to the 2000-2003 years and have accordingly filed a protest with the IRS regarding the resolution of these issues. We have provided for amounts that we believe will be ultimately payable under the proposed adjustments; however, these proposed IRS adjustments, should they be sustained, would result in a tax liability of approximately $25 million in excess of amounts provided for in our consolidated financial statements. In addition, although we believe that the tax effect of the MI and JRMH reorganization should be sustained if audited or otherwise challenged by the IRS, any adjustment by the IRS could have a material impact on the results as reported. See Note 10 for additional information on pending or potential tax issues.
We are under routine tax audit examination in various U.S. state and local taxing jurisdictions in which we have operated. These examinations cover various tax years and are in various stages of finalization. We believe that any income taxes ultimately assessed in the U.S. or by U.S. state and local taxing authorities will not materially exceed amounts for which we have already provided.
We are also under routine tax audit examination in various foreign jurisdictions in which we operate. These examinations cover various tax years and are in various stages of finalization. We believe that any income taxes ultimately assessed in these foreign jurisdictions will not materially exceed amounts for which we have already provided.
Effective January 1, 2007, we will adopt the provisions of FIN 48. As a result, we anticipate we will record an additional tax liability in the range of approximately $10 million to $20 million, with an offset to accumulated deficit.
NOTE 5 - LONG-TERM DEBT AND NOTES PAYABLE
Maturities of long-term debt during the five years subsequent to December 31, 2006 are as follows: 2007 - $256.5 million; 2008 - $4.6 million; 2009 - $4.6 million; 2010 - $0.4 million; and 2011- $0.4 million.
On June 6, 2006, JRM completed a cash tender offer for all its outstanding 11% senior secured notes due 2013 (“JRM Secured Notes”). The tender offer consideration was based on a fixed-spread over specified U.S. Treasury securities, which equated to an offer price of approximately 119% of the principal amount of the notes. JRM used cash on hand to purchase the entire $200 million in aggregate principal amount of the JRM Secured Notes outstanding for approximately $249.0 million, including accrued interest of approximately $10.9 million. As a result of this early retirement of debt, we recognized $49.0 million of expense during the year ended December 31, 2006.
On June 6, 2006, JRM entered into a new $500 million senior secured credit facility with a syndicate of lenders (the “JRM Credit Facility”). The JRM Credit Facility comprises a five-year, $400 million revolving credit (all of which may be used for the issuance of letters of credit and $250 million of which may be used for revolver borrowings), which matures on June 6, 2011, and a six-year, $100 million synthetic letter of credit subfacility, which matures on June 6, 2012. The proceeds of the JRM Credit Facility are available for working capital needs and other general corporate purposes of JRM and its subsidiaries.
JRM’s obligations under the JRM Credit Facility are unconditionally guaranteed by substantially all of JRM’s wholly owned subsidiaries and secured by liens on substantially all of JRM’s and these subsidiaries’ assets (other than cash, cash equivalents, equipment and certain foreign assets), including their major marine vessels. JRM is permitted to prepay amounts outstanding under the JRM Credit Facility at any time without penalty. Other than customary mandatory prepayments on certain contingent events, the JRM Credit Facility requires only interest payments on a quarterly basis until maturity. Loans outstanding under the revolving credit subfacility bear interest at either the Eurodollar rate plus a margin ranging from 2.25% to 2.50% per annum or the base rate plus a margin ranging from 1.25% to 2.25% per annum. The applicable margin for revolving loans varies depending on JRM’s credit ratings. JRM is charged a commitment fee on the unused portions of the $400 million revolving credit subfacility, and that fee varies between 0.375% and 0.50% per annum depending on JRM’s credit ratings. Additionally, JRM is charged a letter of credit fee of between 2.25% and 2.50% per annum with respect to the amount of each letter of credit issued under the revolving credit subfacility. JRM is also charged a fee of 2.60% per annum on the full amount of the synthetic letter of credit subfacility, regardless of whether the subfacility is drawn
upon. An additional 0.125% annual fee is charged on the amount of each letter of credit issued under both subfacilities.
The JRM Credit Facility contains customary financial covenants relating to leverage and interest coverage and includes covenants that restrict, among other things, debt incurrence, liens, investments, acquisitions, asset dispositions, dividends, prepayments of subordinated debt, mergers, transactions with affiliates and capital expenditures. JRM was in compliance with these covenants at December 31, 2006.
On February 23, 2006, JRM cancelled its separate $25 million letter of credit facility entered into on August 25, 2004.
At December 31, 2006, JRM had no borrowings outstanding, and letters of credit issued on the JRM Credit Facility totaled $250.2 million. In addition, JRM had $129.8 million in outstanding unsecured letters of credit under separate arrangements with financial institutions at December 31, 2006.
On December 22, 2005, JRM, as guarantor, and its subsidiary, J. Ray McDermott Middle East, Inc., entered into a $105.2 million unsecured performance guarantee issuance facility with a syndicate of commercial banking institutions. The outstanding amount under this facility is included in the $129.8 million outstanding referenced above. This facility provides credit support for bank guarantees issued in favor of three projects awarded to JRM. The term of this facility is for the duration of these projects, and the average commission rate is less than 4.50% on an annualized basis.
On December 9, 2003, BWXT entered into a three-year, unsecured, $125 million credit facility (the “BWXT Credit Facility”). The BWXT Credit Facility may be increased to a total of $150 million at our discretion, and in fact, it was increased to $135 million in January 2004. In March 2005, the maturity date was extended to March 18, 2010, and on November 7, 2005, BWXT and its lenders amended the BWXT Credit Facility to, among other things, permit the full amount of the facility to be used for loans.
The BWXT Credit Facility is a revolving credit agreement providing for borrowings and issuances of letters of credit in an aggregate amount of up to $135 million. The BWXT Credit Facility requires BWXT to comply with various financial and nonfinancial covenants and reporting requirements. The financial covenants require BWXT to maintain a maximum leverage ratio, a minimum fixed charge coverage ratio and a maximum debt to capitalization ratio. BWXT was in compliance with these covenants at December 31, 2006. The interest rate at December 31, 2006 was 8.75%. BWXT is charged an annual commitment fee of 0.375%, which is payable quarterly. Additionally, BWXT is charged a letter of credit fee of between 1.50% and 2.50% per annum with respect to the amount of each letter of credit issued. An additional 0.125% per annum fee is charged on the amount of each letter of credit issued. At December 31, 2006, BWXT had no borrowings outstanding, and letters of credit outstanding under the facility totaled $50.8 million.
On February 22, 2006, B&W entered into a $650 million senior secured credit facility with a syndicate of lenders (the “B&W Facility”) to replace B&W’s debtor-in-possession credit facility, which was terminated when B&W’s Chapter 11 proceedings were concluded. The B&W Facility includes a five-year, $200 million revolving credit subfacility (the entire availability of which may be used for the issuance of letters of credit or working capital requirements), a six-year, $200 million letter of credit subfacility and a commitment by certain of the lenders to loan B&W up to $250 million in term debt to refinance the $250 million promissory note in connection with the settlement of the B&W Chapter 11 proceedings. The term loan could only be used by B&W in a single draw, and the commitment of the lenders to make this loan was set to expire on December 1, 2006. See Note 20 for additional information concerning the settlement of B&W’s Chapter 11 proceedings.
On November 30, 2006, B&W drew down $250 million on its term loan under the B&W Facility and completed its obligation to pay the $250 million promissory note to the trust on December 1, 2006. This promissory note was recorded in Accrued Cost of The Babcock & Wilcox Company Bankruptcy Settlement on our consolidated balance sheets at its fair value of approximately $245.3 million, and therefore, this retirement resulted in the recognition of approximately $4.7 million of expense. The term loan debt under the B&W Facility is scheduled to mature on February 22, 2012. While not due to mature until 2012, B&W intends to repay the term loan debt during 2007, and therefore, the $250 million outstanding has been classified as current on our consolidated balance sheets.
B&W’s obligations under the B&W Facility are unconditionally guaranteed by all of B&W’s domestic subsidiaries and secured by liens on substantially all of B&W’s and these subsidiaries’ assets, excluding cash and cash equivalents.
Loans outstanding under the revolving credit subfacility bear interest at either the Eurodollar rate plus a margin ranging from 2.75% and 3.25% per annum or the base rate plus a margin ranging from 1.75% to 2.25% per annum. The applicable margin for revolving loans varies depending on B&W’s credit ratings. The applicable margin for the $250 million term loan, which is a Eurodollar rate loan, is 3.0% per annum. The interest rate for the term loan at December 31, 2006 was 8.36%. B&W is charged a commitment fee on the unused portion of the revolving credit subfacility, and that fee varies between 0.25% and 0.50% per annum depending on B&W’s credit ratings. Additionally, B&W is charged a letter of credit fee of between 2.75% and 3.25% per annum with respect to the amount of each letter of credit issued under the revolving credit subfacility. B&W is also charged a fee of 2.85% per annum on the full amount of the synthetic letter of credit subfacility, regardless of whether the subfacility is drawn upon. An additional 0.125% per annum fee is charged on the amount of each letter of credit issued under each subfacility.
If B&W’s leverage ratio is above 2.0 to 1.0, B&W must offer to repay the term loan once each year in an amount equal to the lesser of $50 million and 50% of its excess cash flow. B&W must also prepay the term loan with the proceeds of certain asset sales, casualties, condemnations and debt issuances. Other than these mandatory prepayments, the B&W Facility only requires interest payments for the revolving credit subfacility and the letter of credit subfacility on a quarterly basis until maturity, which is February 22, 2011 and February 22, 2012, respectively. In addition to quarterly interest payments, the term loan requires principal payments, based on 1% of the original principal amount, payable quarterly until maturity, which is February 22, 2012. B&W may prepay amounts outstanding under the B&W Facility at any time without penalty.
The B&W Facility contains customary financial covenants, including maintenance of a maximum leverage ratio and a minimum interest coverage ratio, and covenants that, among other things, restrict B&W’s ability to incur debt, create liens, make investments and acquisitions, sell assets, pay dividends, prepay subordinated debt, merge with other entities, engage in transactions with affiliates and make capital expenditures. The B&W Facility also contains customary events of default. B&W was in compliance with these covenants at December 31, 2006.
As of December 31, 2006, B&W had outstanding borrowings of $250 million under its term loan feature of the B&W Facility, and letters of credit issued on the B&W Facility totaled $229.8 million.
Our subsidiaries are generally restricted, as a result of covenants in debt instruments, in their ability to transfer funds to MII and its other subsidiaries through cash dividends or through unsecured loans or investments.
NOTE 6 - PENSION PLANS AND POSTRETIREMENT BENEFITS
We provide retirement benefits, primarily through noncontributory pension plans, for most of our regular full-time employees. We do not provide retirement benefits to certain nonresident alien employees of foreign subsidiaries who are not citizens of a European Community country or who do not earn income in the United States, Canada or the United Kingdom. We base our salaried plan benefits on final average compensation and years of service, while we base our hourly plan benefits on a flat benefit rate and years of service. Our funding policy is to fund applicable pension plans to meet the minimum funding requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”) and, generally, to fund other pension plans as recommended by the respective plan actuaries and in accordance with applicable law. The Pension Protection Act of 2006 (the “Act”) replaces the current funding provisions for single-employer defined benefit plans. Funding provisions under the Act accelerate funding requirements to ensure full funding of benefits accrued. The Act will become effective in 2008, and we do not anticipate any material impact on our consolidated financial condition or cash flows.
Effective December 31, 2006, we adopted SFAS No. 158, “Employers Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”). In accordance with SFAS No. 158, the funded status of our defined benefit pension plans and postretirement plans has been recognized on our consolidated balance sheets. The initial impact of the standard is to recognize in accumulated other comprehensive loss all unrecognized prior service costs and net actuarial gains and losses. Furthermore, additional minimum pension liabilities and associated intangible assets required under previous accounting rules have been reversed.
Effective January 31, 2005, MI spun off to B&W the assets and liabilities associated with B&W’s portion of MI’s pension plan to a plan sponsored by B&W. However, our disclosures in this footnote include the B&W plan even though, at December 31, 2005, B&W was not a consolidated subsidiary. At December 31, 2005, the B&W plan had a projected benefit obligation of $693.2 million, fair value of plan assets of $482.8 million and a recognized obligation of $40.4 million. The deferred liability of the B&W pension plan spin-off was $150.1 million, of which $110.4 million was included in minimum pension liability, $9.0 million in intangible pension assets and the remaining $30.7 million was charged to capital in excess of par. Approximately 46% of the participants in the MI plan at January 31, 2005 transferred to this new B&W-sponsored plan.
During the year ended December 31, 2004, we terminated one of our pension plans in the United Kingdom and recorded a gain of approximately $27.7 million related to the termination. In December 2005, we recorded an additional gain totaling $1.4 million related to the finalization of the termination.
Effective December 31, 2004, the McDermott International, Inc. Supplemental Executive Retirement Plan, Amended and Restated effective December 1, 1999 (the “Old SERP Plan”) was terminated, and we adopted the McDermott International, Inc. Supplemental Executive Retirement Plan effective January 1, 2005 (the “New SERP Plan”). The Old SERP Plan was a defined benefit plan, while the New SERP Plan is a defined contribution plan. The cessation of benefits of the Old SERP Plan generally did not affect the rights of retired or disabled participants (or their spouses) who were receiving benefits under that plan as of December 31, 2004. However, some of the retired participants elected to cancel their deferral elections and receive a discounted lump-sum distribution of their entire interest in the Old SERP Plan in 2005. All active participants in the Old SERP Plan on December 31, 2004 became participants in the New SERP Plan on January 1, 2005. We recorded a settlement and curtailment gain in 2004 of approximately $4.6 million in connection with the termination of the Old SERP Plan. We also recorded expenses related to the New SERP Plan of approximately $2.9 million, $1.3 million and $1.4 million in the years ended December 31, 2006, 2005 and 2004, respectively.
We make available postretirement health care and life insurance benefits to certain retired union employees based on their union contracts.
Obligations and Funded Status (Including B&W)
Obligations and Funded Status (Including B&W)
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for all pension plans were $2,521.9 million, $2,397.0 million and $2,050.2 million, respectively, at December 31, 2006, and $2,313.2 million, $2,191.0 million and $1,706.3 million, respectively, at December 31, 2005. The accumulated benefit obligation was in excess of plan assets for all of our plans.
(1) Includes approximately $35 million of expense which was recorded in B&W attributable to the spin-off of the B&W pension plan from MI.
Additional Information
The increase in accumulated other comprehensive loss of $124.9 million for pension benefits due to the adoption of SFAS No. 158 includes a reclassification of $24.5 million from intangible assets. The decrease in the minimum pension liability of $85.0 million is net of an increase of $39.8 million due to the reconsolidation of B&W.
We expect to recognize the following amounts in other comprehensive loss as components of net periodic benefit cost in the next fiscal year:
Assumptions
The expected rate of return on plan assets assumption is based on the long-term expected returns for the investment mix of assets currently in the portfolio. In setting this rate, we use a building-block approach. Historic real return trends for the various asset classes in the plan’s portfolio are combined with anticipated future market conditions to estimate the real rate of return for each class. These rates are then adjusted for anticipated future inflation to determine estimated nominal rates of return for each class. The expected rate of return on plan assets is determined to be the weighted average of the nominal returns based on the weightings of the classes within the total asset portfolio.
We have been using an expected return on plan assets assumption of 8.5%, which is consistent with the long-term asset returns of the portfolio.
Assumed health-care cost trend rates have a significant effect on the amounts we report for our health-care plan. A one-percentage-point change in our assumed health-care cost trend rates would have the following effects:
Plan Assets
Our domestic pension plans’ weighted average asset allocations at December 31, 2006 and 2005 by asset category were as follows:
Our foreign pension plan’s weighted average asset allocations at December 31, 2006 and 2005 by asset category were as follows:
For the years ended December 31, 2006 and 2005, the investment return on domestic pension plan assets (before deductions for management fees) was approximately 12.4% and 8.6%, respectively. The assets of the domestic pension plans are commingled for investment purposes and held by the Trustee, Mellon Trust of New England, N.A., in the McDermott Incorporated Master Trust (the “Master Trust”).
Investment Goals
General
The overall investment strategy of the pension trusts is to emphasize long term growth of principal, while avoiding excessive risk and to minimize the probability of loss of principal over the long term. The specific investment goals that have been set for the pension trusts in the aggregate are (1) to ensure that plan liabilities are met when due and (2) to achieve an investment return on trust assets consistent with a reasonable level of risk that exceeds the applicable custom benchmark described below, and over the long term, exceeds the assumed actuarial rate of return set by each of the plans’ actuaries.
Allocations to each asset class for both domestic and foreign plans are reviewed periodically and rebalanced, if appropriate, to assure the continued relevance of the goals, objectives and strategies.
The pension trusts for both our domestic and foreign plans employ a professional investment advisor, and a number of professional investment managers whose individual benchmarks are, in the aggregate, consistent with the plan’s overall investment objectives.
The goals of each investment manager are (1) to meet (in the case of passive accounts) or exceed (for actively managed accounts) the benchmark selected and agreed upon by the manager and the Trust and (2) to display an overall level of risk in its portfolio that is consistent with the risk associated with the agreed upon benchmark.
The investment performance of total portfolios, as well as asset class components, is periodically measured against commonly accepted benchmarks, including the individual investment manager benchmarks. In evaluating investment manager performance, consideration is also given to personnel, strategy, research capabilities, organizational and business matters, adherence to discipline and other qualitative factors that may impact ability to achieve desired investment results.
Domestic Plans
Based on the liability profile of the domestic plans, a well-diversified policy of 60% equities and 40% fixed income has been determined to be appropriate for the Master Trust in terms of risk/reward trade-off, taking into account the expected funded status of the plans, cash contributions and expense. Accordingly, the following asset allocation policy has been adopted for the Master Trust:
The Master Trust’s overall investment policy is reviewed at least annually to assure the continued relevance of the goals, objectives and strategies.
As stated above, one of the goals of the Master Trust is to outperform a custom benchmark which is comprised as follows:
The performance objective for the Master Trust is to seek to outperform this custom benchmark by 0.75% per annum (net of fees) or more over rolling three-year periods.
The active risk of the Master Trust (also known as tracking error) is a numerical measure of the Master Trust’s risk relative to the custom benchmark. Active risk is defined as the standard deviation of the relative return, and the convention is to compute it from monthly observations and then convert it to an annualized figure by multiplying it by the square root of 12. (In a normal distribution, two-thirds of the observations will fall within one standard deviation of the average. So if the expected standard deviation was 2% and the expected average was 0%, then one-sixth of the observations will be more than 2% greater than the average and one-sixth will be more than 2% below the average.) Active risk can be either ex post (measuring the actual standard deviation of the excess returns achieved by the Manager) or ex ante (using a statistical model to estimate the likely outcome.)
The risk objective in respect of the Master Trust is to seek to achieve an ex post active risk of less than 2% per annum over rolling three-year periods.
Foreign Plans
We sponsor various foreign plans through certain of our foreign subsidiaries.
J. Ray McDermott SA TCN Employees Pension Plan (the “TCN Plan”)
For the years ended December 31, 2006 and 2005, the TCN Plan’s asset allocation was targeted at 50% United States equity securities and 50% United States debt securities. For the years ended December 31, 2006 and 2005, the investments return on TCN Plan assets (gross of management fees) was 13.7% and 5.1%, respectively. Following an asset/liability modeling study conducted in 2004, the following asset allocation policy was determined to be suitable and has been adopted for this plan:
One of the goals of the TCN Plan is to outperform a custom index, which is comprised as follows:
The performance objective of the TCN Plan is to seek to outperform this custom benchmark on a net-of-fees basis over rolling three-year periods.
Canadian Plans
Our Canadian subsidiary provides benefits under various plans to certain salaried and hourly employees. The assets of the Canadian pension plans are commingled for investment purposes and held by the Trustee, CIBC Mellon Trust Company in the Babcock & Wilcox Canada, Ltd. Master Trust (the “Canadian Master Trust”). For the year ended December 31, 2006, the investment return on Canadian pension plan assets (gross of management fees) was 10.7%.
Based on the liability profile and risk tolerance of the Canadian plans, a well-diversified policy of 65% equities and 35% debt securities has been determined to be appropriate for the Canadian Master Trust. Accordingly, the following asset allocation policy has been adopted.
The performance objective of the Canadian Master Trust is to achieve annualized returns, on a net-of-fees basis, that outperform the following benchmark by 0.50% or more over rolling four-year periods.
Diamond Power Specialty Limited Retirement Benefits Plan (the “Diamond UK Plan”)
B&W’s subsidiary in the U.K. provides retirement benefits under the Diamond UK plan. The assets of the Diamond UK Plan are held in trust by State Street Bank & Trust Company, HSBC Global Investor Services, Citibank and Pension Funds Trustee Limited. For the year ended December 31, 2006, the investment return on the Diamond UK Plan was 16.5%.
Based on the liability profile and risk tolerance of the Diamond UK Plan, a well-diversified policy of 60% equities and 40% fixed income securities has been determined to be appropriate. Accordingly, the following asset allocation policy has been adopted:
The performance objective of the Diamond UK Plan is to track the following equity and index-linked gilt benchmarks within their tracking ranges and to outperform the following corporate bond and Long-Dated Gilt benchmarks by 0.75% per year and 0.6% per year, respectively, gross of fees, over rolling three-year periods.
Cash Flows
Contributions
We expect to contribute approximately $99.1 million to our pension plans, which includes approximately $58.0 million for B&W, $35.8 million for BWXT and $5.3 million for JRAY pension plans, respectively, and $12.1 million to our other postretirement benefit plans in 2007.
Estimated Future Benefit Payments
We expect the following benefit payments, which reflect expected future service, as appropriate, to be made from our domestic and foreign plans:
NOTE 7 - ASSET SALES AND IMPAIRMENT OF LONG-LIVED ASSETS
We had losses on the sale of assets totaling approximately $15.0 million in 2006, primarily in our Offshore Oil and Gas Construction segment, which includes a loss of approximately $16.4 million associated with our joint venture in Mexico, offset by gains on sales of various non-strategic assets, primarily in our Government Operations segment.
Impairment losses to write down property, plant and equipment to estimated fair values are summarized by segment as follows:
Property, plant and equipment and other assets - assets to be held and used
During the year ended December 31, 2004, our Offshore Oil and Gas Construction segment recorded an impairment loss of $0.1 million for miscellaneous equipment at one of our fabrication facilities. Also in 2004, our Government Operations segment recorded impairment losses totaling $0.4 million on machinery and equipment that was no longer expected to recover its carrying value through future cash flows. We determined fair value based on valuations of comparable equipment. Prior to the impairment, this machinery and equipment had a total net book value of approximately $0.5 million.
Property, plant and equipment and other assets - assets to be disposed of
During the year ended December 31, 2004, our Offshore Oil and Gas Construction segment recorded an impairment loss totaling approximately $2.2 million to reduce the net book value of one of our vessels and certain machinery and equipment to net realizable value. Prior to the impairment charges, this equipment had a total net book value of approximately $46.7 million.
NOTE 8 - CAPITAL STOCK
The Panamanian regulations that relate to acquisitions of securities of companies registered with the Panamanian National Securities Commission, such as MII, require, among other matters, that detailed disclosure concerning an offeror be finalized before that person acquires beneficial ownership of more than 5% of the outstanding shares of any class of our stock pursuant to a tender offer. The detailed disclosure is subject to review by either the Panamanian National Securities Commission or our Board of Directors. Transfers of shares of common stock in violation of these regulations are invalid and cannot be registered for transfer.
We issue shares of our common stock in connection with our 2001 Directors and Officers Long-Term Incentive Plan, our 1996 Officer Long-Term Incentive Plan (and its predecessor programs) and contributions to our Thrift Plan. At December 31, 2006 and 2005, 7,499,513 and 11,070,566 shares of common stock, respectively, were reserved for issuance in connection with those plans.
Common Stock Split
On May 3, 2006, our Board of Directors declared a three-for-two stock split effected in the form of a stock dividend. The dividend was paid on May 31, 2006 to stockholders of record as of the close of business on May 17, 2006. All share and per share information in the accompanying financial statements and notes has been retroactively adjusted to reflect the stock split.
MII Preferred Stock
We designated a series of our authorized but unissued preferred stock as Series D Participating Preferred Stock in connection with our Stockholder Rights Plan, which expired pursuant to its terms in November 2006. As of December 31, 2006, no shares of Series D Participating Preferred Stock were outstanding.
Our issuance of shares of preferred stock in the future and the specific terms thereof, such as the dividend rights, conversion rights, voting rights, redemption prices and similar matters, may be authorized by our Board of Directors without stockholder approval.
NOTE 9 - STOCK PLANS
At December 31, 2006, we had several stock-based employee compensation plans, which are described below. Where required, disclosures have been adjusted for our May 2006 stock split effected in the form of a stock dividend. See Note 8 for further information regarding our stock split.
2001 Directors and Officers Long-Term Incentive Plan
In May 2006, our shareholders approved the amended and restated 2001 Directors and Officers Long-Term Incentive Plan. Members of the Board of Directors, executive officers, key employees and consultants are eligible to participate in the plan. The Compensation Committee of the Board of Directors selects the participants for the plan. The plan provides for a number of forms of stock-based compensation, including nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, deferred stock units, performance shares and performance units, subject to satisfaction of specific performance goals. In addition to shares previously available under this stock plan that have not been awarded, or that were subject to awards that have been canceled, terminated, forfeited, expired, settled in cash, or exchanged for consideration not involving shares, up to 3,750,000 additional shares of our common stock were authorized for issuance through the plan in May 2006. Options to purchase shares are granted at not less than 100% of the fair market value (average of the high and low trading price) on the date of grant, become exercisable at such time or times as determined when granted and expire not more than seven years after the date of the grant. Options granted prior to the amendment of this plan expire not more than ten years after the date of the grant.
1997 Director Stock Program
Under our 1997 Director Stock Program, we grant options to purchase 1,350 shares of our common stock in the first year of a director’s term and 450 shares in subsequent years of such term at a purchase price that is not less than 100% of the fair market value on the date of grant. These options become exercisable, in full, six months after the date of grant and expire ten years and one day after the date of grant. Under this program, we also grant rights to purchase 675 shares in the first year of a director’s term and 225 shares in subsequent years of such term at par value ($1.00 per share). These shares are subject to transfer restrictions and forfeiture provisions that lapse at the end of the director’s term.
At December 31, 2006, we had a total of 4,116,418 shares of our common stock available for award under the 2001 Directors and Officers Long-Term Incentive Plan and the 1997 Director Stock Program.
In the event of a change in control of our company, all these stock-based compensation programs have provisions that may cause restrictions to lapse and accelerate the exercisability of outstanding options.
Pursuant to the adoption of SFAS No. 123(R), we recognized stock-based compensation expense of $4.4 million related to employee stock options during the year ended December 31, 2006. During the years ended December 31, 2005 and 2004, there was no stock-based compensation expense for employee stock options, other than for stock options subject to variable accounting. These stock options subject to variable accounting resulted from the cancellation and reissuance of stock options during the year ended December 31, 2000. Under APB No. 25 and its related interpretations, the cancellation and reissuance of stock options within six months of each other triggered mark-to-market accounting. For stock options granted prior to the adoption of SFAS No. 123(R), the effect on net income and earnings per share, if we had applied the fair value recognition provisions of SFAS No. 123 to employee stock options, would have been as follows for the years ended December 31, 2005 and 2004:
For our other stock-based compensation awards, such as restricted stock and performance units, the adoption of SFAS No. 123(R) did not significantly change our accounting policies for the recognition of compensation expense, as we have recognized expense for those awards in prior periods. Total compensation expense recognized for the years ended December 31, 2006, 2005 and 2004 was as follows:
The impact on basic earnings per share of stock-based compensation expense recognized for the years ended December 31, 2006, 2005 and 2004 was $0.13, $0.01 and $0.05 per share, respectively, and on diluted earnings per share was $0.12, $0.01 and $0.05 per share, respectively.
As of December 31, 2006, total unrecognized estimated compensation expense related to nonvested awards was $14.7 million, net of estimated tax benefits of $6.9 million. The total gross unrecognized estimated compensation expense of $21.6 million consists of $3.6 million for stock options, $0.2 million for restricted stock and $17.8 million for performance shares, which are expected to be recognized over weighted average periods of 0.9 years, 0.2 years and 2.4 years, respectively. Performance and deferred stock units are marked-to-market at the end of each quarter, so there was no unrecognized compensation expense as of December 31, 2006.
Stock Options
The fair value of each option grant was estimated at the date of grant using Black-Scholes, with the following weighted-average assumptions:
The risk-free interest rate is based on the implied yield on a U.S. Treasury zero-coupon issue with a remaining term equal to the expected life of the option. The expected volatility is based on historical implied volatility from publicly traded options on our common stock, historical implied volatility of the price of our common stock and other factors. The expected life of the option is based on observed historical patterns. The expected dividend yield is based on the projected annual dividend payment per share divided by the stock price at the date of grant. This amount is zero because we have not paid cash dividends for several years and do not expect to pay cash dividends at this time.
The following table summarizes activity for our stock options for the year ended December 31, 2006 (share data in thousands):
The aggregate intrinsic value included in the table above represents the total pretax intrinsic value that would have been received by the option holders had all option holders exercised their options on December 31, 2006. The intrinsic value is calculated as the total number of option shares multiplied by the difference between the closing price of our common stock on the last trading day of each period and the exercise price of the options. This amount changes based on the fair market value of our common stock.
The weighted average fair value of the stock options granted in the years ended December 31, 2006, 2005 and 2004 was $20.63, $20.65 and $8.21, respectively. The total fair value of shares vested during the years ended December 31, 2006, 2005 and 2004 was $5.0 million, $6.7 million and $9.1 million, respectively.
During the years ended December 31, 2006, 2005 and 2004, the total intrinsic value of stock options exercised was $102.4 million, $71.0 million and $1.8 million, respectively. We recorded cash received in the years ended December 31, 2006, 2005 and 2004 from the exercise of these stock options totaling $21.5 million, $53.0 million and $2.9 million, respectively. The actual tax benefits realized related to the stock options exercised during the years ended December 31, 2006, 2005 and 2004 was $17.9 million, $14.2 million and $0.4 million, respectively. The total tax benefits realized for the years ended December 31, 2006, 2005 and 2004 does not include approximately $14.3 million related to JRM, as this total amount has been deferred until utilization of the net operating losses causes the benefits to be realized. See Note 4 for additional information related to JRM’s net operating losses.
Restricted Stock
Nonvested restricted stock awards as of December 31, 2006 and changes during the year ended December 31, 2006 were as follows (share data in thousands):
Performance Shares
Nonvested performance share awards as of December 31, 2006 and changes during the year ended December 31, 2006 were as follows (share data in thousands):
There were no shares vested during the years ended December 31, 2006, 2005 and 2004.
Performance and Deferred Stock Units
Nonvested performance and deferred stock unit awards as of December 31, 2006 and changes during the year ended December 31, 2006 were as follows (share data in thousands):
The aggregate intrinsic value included in the table above represents the total pretax intrinsic value recorded as a liability at December 31, 2006 in the consolidated balance sheets. During the year ended December 31, 2006, we paid $26.2 million for the settlement of vested performance and deferred stock units. There were no such settlements during the years ended December 31, 2005 and 2004.
Thrift Plan
On November 12, 1991, 7,500,000 of the authorized and unissued shares of MII common stock were reserved for issuance for the employer match to the Thrift Plan for Employees of McDermott Incorporated and Participating Subsidiary and Affiliated Companies (the “Thrift Plan”). On October 11, 2002, an additional 7,500,000 of the authorized and unissued shares of MII common stock were reserved for issuance for the employer match to the Thrift Plan. Those matching employer contributions equal 50% of the first 6% of compensation, as defined in the Thrift Plan, contributed by participants, and fully vest and are nonforfeitable after three years of service or upon retirement, death, lay-off or approved disability. The Thrift Plan allows employees to sell their interest in MII’s common stock fund at any time, except as limited by applicable securities laws and regulations. During the years ended December 31, 2006, 2005 and 2004, we issued 236,930, 365,772 and 936,242 shares, respectively, of MII’s common stock as employer contributions pursuant to the Thrift Plan. At December 31, 2006, 3,383,095 shares of MII’s common stock remained available for issuance under the Thrift Plan.
NOTE 10 - CONTINGENCIES AND COMMITMENTS
Investigations and Litigation
Antitrust Litigation
In June 1998, Shell Offshore, Inc. and several related entities filed a lawsuit in the U.S. District Court for the Southern District of Texas against MII, JRM, MI, certain JRM subsidiaries and others, including Heerema Marine Contractors (“Heerema”), alleging that the defendants engaged in anticompetitive acts in violation of Sections 1 and 2 of the Sherman Act (the “Antitrust Litigation”). Subsequently, the following parties (acting for themselves and, in certain cases, on behalf of their respective co-venturers and for whom they operate) intervened as plaintiffs in the Antitrust Litigation: Amoco Production Company and B.P. Exploration & Oil, Inc.; Amerada Hess Corporation; Conoco Inc. and certain of its affiliates; Texaco Exploration and Production Inc. and certain of its affiliates (collectively, “Chevron Texaco”); Elf Exploration UK PLC and Elf Norge a.s.; Burlington Resources Offshore, Inc.; The Louisiana Land & Exploration Company; Marathon Oil Company and certain of its affiliates; VK-Main Pass Gathering Company, L.L.C.; Green Canyon Pipeline Company, L.L.C.; Delos Gathering Company, L.L.C.; Chevron U.S.A. Inc. and Chevron Overseas Petroleum Inc.; Shell U.K. Limited and certain of its affiliates; Woodside Energy, Ltd; and Saga Petroleum, S.A. Also, in December 1998, Total Oil Marine p.l.c. and Norsk Hydro Produksjon a.s., individually and on behalf of their respective co-venturers, filed similar lawsuits in the same court, and those lawsuits were consolidated with the Antitrust Litigation. In addition to seeking injunctive relief, actual damages and attorneys’ fees, the plaintiffs in the Antitrust Litigation made a claim for treble damages and interest. In December 2003, Chevron Texaco also filed suit in the High Court of London alleging antitrust injury regarding seven projects completed in the period from 1993 to 1997.
In November 2006, we entered into a settlement which provides a full and final release of the Antitrust Litigation, including the suit in London, and which also resolved the related Petronius Litigation. All payments under the settlement have been made, and the suits have been dismissed.
Petronius Litigation
In December 1998, a subsidiary of JRM (the “Operator Subsidiary”) was in the process of installing a module on the Petronius platform in the Gulf of Mexico for Texaco Exploration and Production, Inc. (“Texaco”) when the main hoist load line failed, resulting in the loss of the module. In December 1999, Texaco filed a lawsuit in federal district court in Louisiana seeking consequential damages for delays resulting from the incident, as well as costs incurred to complete the project with another contractor and uninsured losses. Both the Operator Subsidiary and another subsidiary of JRM, the owner of the vessel that attempted the lift of the deck module (the “Owner Subsidiary”), were defendants in this litigation. In addition to Texaco’s claims in the federal court proceeding, damages for the loss of the module were sought by Texaco’s builder’s risk insurers in claims against the Owner Subsidiary and several other defendants. Total damages sought by Texaco and its builder’s risk insurers in the proceeding approximated $280 million. The Operator Subsidiary initiated an arbitration proceeding under the arbitration provisions of the installation contract to collect $23 million due for work performed under the contract.
The settlement of the Antitrust Litigation, noted above, includes a settlement of the Petronius Litigation, and this matter has been fully and finally resolved.
Apollo/Parks Township Claims - Hall Litigation
On June 7, 1994, Donald F. Hall, Mary Ann Hall and others filed suit against B&W and Atlantic Richfield Company (“ARCO”) in the United States District Court for the Western District of Pennsylvania. The suit, which has been amended from time to time, presently involves approximately 500 separate claims for compensatory and punitive damages relating to the operation of two nuclear fuel processing facilities located in Apollo and Parks Township, Pennsylvania (the “Hall Litigation”). The plaintiffs in the Hall Litigation allege, among other things, that they suffered death, personal injury, property damage and other damages as a result of radioactive emissions from these facilities. In September 1998, a jury found B&W and ARCO liable to eight plaintiffs in the first cases brought to trial, awarding $36.7 million in compensatory damages. In the course of that trial, B&W settled all pending punitive damages claims in the Hall Litigation for $8.0 million. In June 1999, the Court set aside the $36.7 million judgment and ordered a new trial on all issues. In November 1999, the Court allowed an interlocutory appeal by the plaintiffs of some of the issues, including the granting of the new trial and the Court’s rulings on specified evidentiary matters, which, following B&W’s Chapter 11 bankruptcy filing, the Third Circuit Court of Appeals declined to accept for review.
B&W’s Chapter 11 plan of reorganization did not impair the claims against B&W for nuclear-related injuries allegedly arising from the operation of the nuclear-fuel processing facilities in Apollo and Parks Township, including the claims asserted in the Hall Litigation (the “Apollo/Parks Township Claims”), which were permitted to pass through the bankruptcy proceeding unaffected by it. Nevertheless, during the process of confirmation of that plan, B&W, representatives of the individuals who have asserted Apollo/Parks Township Claims in the pending Hall Litigation and ARCO negotiated a form of settlement agreement in the context of the B&W Chapter 11 proceedings (the “Disputed Agreement”), which was approved by the Bankruptcy Court, subject to certain conditions, at the same time that the B&W plan of reorganization was confirmed. That Disputed Agreement contemplated, among other things, that:
•
B&W and ARCO would be provided full and complete releases with respect to all Apollo/Parks Township Claims from each of the “Apollo/Parks Township Releasors” (as that term was defined in the form of settlement agreement generally to mean the existing claimants in the Hall Litigation and other Apollo/Parks Township present claimants that are represented by counsel for the claimants in the Hall Litigation);
•
ARCO would make a $27.5 million cash payment to the Apollo/Parks Township Releasors after all conditions precedent to such payment, as set forth in the form of settlement agreement, have occurred;
•
B&W would make a $47.5 million cash payment to the Apollo/Parks Township Releasors after all conditions precedent to such payment, as set forth in the form of settlement agreement, have occurred. This amount has been included in Other Liabilities on our consolidated balance sheets;
•
B&W would make a $12.5 million payment to the Apollo/Parks Township Releasors on the third anniversary of the effective date of the Plan, or after all conditions precedent to such payment, as set forth in the form of settlement agreement, have occurred. This amount has been included in Other Liabilities on our consolidated balance sheets; and
•
B&W and ARCO would retain all insurance rights relating to all Apollo/Parks Township Claims.
After the B&W plan of reorganization became effective, counsel for the Hall Claimants were unwilling to proceed with the Disputed Agreement as drafted, and B&W and ARCO filed a joint motion with the United States Bankruptcy Court for the Eastern District of Louisiana, the court which presided over the B&W Chapter 11 proceedings, to enforce the settlement. In February 2007, the Bankruptcy Court denied B&W’s motion to enforce the settlement agreement. These claims will now proceed through the litigation process before the Pennsylvania Court. Trial of the claims of the original eight plaintiffs has been set by the Pennsylvania Court for November 5, 2007 before a jury.
We believe these claims will be resolved within the limits of coverage of our insurance policies. However, should any judgment on these claims prove excessive, or additional future claims be asserted, there may be an issue
as to whether our insurance coverage is adequate, and we may be materially and adversely impacted if our liabilities exceed our coverage and the amount we have reserved for these claims.
See Note 20 for additional information on B&W’s Chapter 11 proceedings.
Citgo Litigation and Settlement
On August 13, 2003, a proceeding entitled Citgo Petroleum Corporation and PDV Midwest Refinery L.L.C. v. McDermott International, Inc, et al., (the “Citgo Action”) was filed in the Circuit Court of Cook County, Illinois, alleging claims against B&W, MII, JRM, MI, and J. Ray McDermott, Inc. (“JRMI”) for damages in connection with the manufacture and sale by a former B&W division of a pipe fitting facility in 1981 that allegedly caused an August 14, 2001 fire at a refinery in the Chicago, Illinois area, which refinery is owned and operated by the plaintiffs. Citgo’s insurers and Certain Underwriters at Lloyd’s, London (“Lloyd’s”) intervened in the Citgo Action for recovery of amounts they paid to Citgo under business interruption policies. Plaintiffs sought damages of approximately $600 million, including claims for damage to property and consequential damages. In October 2004, Citgo’s claims against MII, JRM, JRMI and MI were dismissed by the court without prejudice to the ability of plaintiffs to refile such claims against those entities upon the showing of appropriate evidence. On March 2, 2005, B&W filed a third-party claim against the former owner of the refinery, Unocal Corporation, seeking contribution and indemnity, which claim was dismissed by the Court in November 2005. B&W appealed that decision and the court of appeals upheld the dismissal. B&W subsequently filed an appeal with the Supreme Court of Illinois. Trial of the Citgo Action commenced before a jury on October 2, 2006, and on November 6, 2006, judgment was entered against B&W in the amount of approximately $387.5 million.
Although we have insurance that provides coverage for claims of the nature asserted in this matter up to limits of liability of $375 million, subject to certain terms and conditions, our third layer excess insurer, which provides $125 million in coverage for liability in excess of $200 million, denied coverage on the basis of an alleged failure to give timely notice of the claim under policy and our fourth layer excess insurers, American Home Assurance Company and Navigators Insurance Services of Texas, Inc. (collectively, “AHAC”), which provide $50 million in coverage for liability in excess of $325 million, initially reserved their rights to deny coverage and are now seeking a judicial declaration that there is no coverage under the policy, in a lawsuit entitled American Home Assurance Company, et al. v. The Babcock & Wilcox Company, in the United States District Court for the Eastern District of New York. B&W filed suit against AHAC in Civil District Court for the Parish of Orleans, State of Louisiana, seeking a judicial declaration of coverage and damages for bad faith in handling the claim. B&W has also filed suit against our broker for loss of the insurance coverage in the event that any of the insurers providing this coverage are successful in a denial of coverage.
In December 2005, with Bankruptcy Court approval, B&W entered into a settlement agreement limiting its exposure under the Citgo Action (“Original Settlement”). Under the terms of the Original Settlement, B&W paid $7.5 million as directed by the plaintiffs upon the effective date of the plan of reorganization. In addition, the Original Settlement provided that should the plaintiffs be awarded damages in excess of $250 million in these proceedings, B&W would be obligated to pay the damages in excess of $250 million subject to a maximum of $42.5 million. This $42.5 million amount, which was not recorded in our financial statements, would be payable by B&W only after all rights and claims are exhausted against B&W’s insurers and its broker. In addition, we agreed with our excess casualty insurers that in the event they are required to pay in excess of $15 million to resolve the Citgo Action, we would pay a loss penalty premium over four years.
In February 2007, we entered into a final settlement of the Citgo Action (“Final Settlement”) which provides that in lieu of the Original Settlement potential payment by B&W of an additional amount up to $42.5 million, B&W will pay $10 million to the plaintiffs and assign its rights against Unocal Corporation, our broker and our third and fourth layer insurers to the plaintiffs. In the event of any recovery from our broker or our third layer insurer, B&W will be entitled to 33.3% of such amounts up to full recovery of its $10 million payment to the plaintiffs. In accordance with the terms of the Final Settlement, B&W has paid $10 million to the plaintiffs. Additionally, our excess casualty insurers have advised us that they believe the loss penalty premium described above remains payable over four years.
Other Litigation and Settlements
On or about August 23, 2004, a declaratory judgment action entitled Certain Underwriters at Lloyd’s London, et al v. J. Ray McDermott, Inc. et al, was filed by certain underwriters at Lloyd’s, London and Threadneedle Insurance Company Limited (the “London Insurers”), in the 23rd Judicial District Court, Assumption Parish, Louisiana, against MII, JRMI and two insurer defendants, Travelers and INA, seeking a declaration that the London Insurers have no obligation to indemnify MII and JRMI for certain bodily injury claims, including claims for asbestos and welding rod fume personal injury which have been filed by claimants in various state courts, and an environmental claim involving B&W. Additionally, Travelers filed a cross-claim requesting a declaration of non-coverage in approximately 20 underlying matters. This proceeding was stayed by the state court on January 3, 2005 based on the consideration of certain of the claims in litigation pending before the 58th Judicial District Court of Jefferson County, Texas, in a matter entitled Benoit, et al., v. J. Ray McDermott, Inc., et al. The London Insurers, Travelers and INA have filed motions for reconsideration of the January 3, 2005 stay order.
On June 1, 2005, a proceeding entitled Iroquois Falls Power Corp v. Jacobs Canada Inc., et al., was filed in the Superior Court of Justice, in Ontario, Canada, alleging damages of approximately $16 million (Canadian) for remedial work, loss of profits and related engineering/redesign costs due to the alleged breach by Jacobs Canada Inc. (formerly Delta Hudson Engineering Limited (“Delta”)), of its engineering design obligations relating to the supply and installation of heat recovery steam generators (“HRSGs”). In addition to Jacobs, the proceeding names as defendants MI, which provided a guarantee to certain obligations of its then affiliate, Delta, and two bonding companies with whom MII entered into an indemnity arrangement. Pursuant to a subcontract with Delta, B&W supplied and installed the HRSGs at issue. Discovery is ongoing, and no trial date has been set. We plan to vigorously defend the matter. However, the ultimate outcome of these proceedings is uncertain, and an adverse ruling could have a material adverse impact on our consolidated financial position, results of operations and cash flows.
In the proceeding entitled Antoine, et al. vs. J. Ray McDermott, Inc., et al., filed in the 24th Judicial District Court, Jefferson Parish, Louisiana by approximately 88 plaintiffs against approximately 215 defendants, including JRMI and Delta Hudson Engineering Corporation (“DHEC”), another affiliate of ours, the plaintiffs generally alleged injuries for exposure to asbestos, and unspecified chemicals, metals and noise while the plaintiffs were allegedly employed as Jones Act seamen. Approximately 70 plaintiffs alleged employment by JRMI or DHEC in that capacity. In early 2006, JRMI and DHEC filed various motions, including a motion to dismiss asserting that the plaintiffs’ claims were improperly joined together, which motion was granted by the court on January 10, 2007. Plaintiffs’ claims have been dismissed without prejudice to their right to refile their claims.
In 2003, we received a favorable arbitration award for one of our claims related to a project in India completed in the 1980s. The award, which with interest and costs is approximately $50 million, was appealed to the Supreme Court of India. On May 28, 2005, we received a favorable award for the remainder of our claim in the approximate amount of $48 million, including interest and costs, which was also appealed. The Supreme Court of India heard the consolidated appeal in late October 2005 and, in May 2006, issued a decision reducing the total of the awards to approximately $90 million, including interest and costs, but otherwise affirming the awards. The Defendants applied for rehearing of this decision, which was denied in October 2006. We intend to institute and vigorously pursue collection efforts. We have not recognized as income any amounts associated with either award, as collection of these amounts is uncertain.
Additionally, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including, among other things:
•
performance or warranty-related matters under our customer and supplier contracts and other business arrangements; and
•
other workers’ compensation claims, Jones Act claims, premises liability claims and other claims.
In our management’s opinion, based upon our prior experience, none of these other litigation proceedings, disputes and claims will have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Environmental Matters
We have been identified as a potentially responsible party at various cleanup sites under the Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”). CERCLA and other
environmental laws can impose liability for the entire cost of cleanup on any of the potentially responsible parties, regardless of fault or the lawfulness of the original conduct. Generally, however, where there are multiple responsible parties, a final allocation of costs is made based on the amount and type of wastes disposed of by each party and the number of financially viable parties, although this may not be the case with respect to any particular site. We have not been determined to be a major contributor of wastes to any of these sites. On the basis of our relative contribution of waste to each site, we expect our share of the ultimate liability for the various sites will not have a material adverse effect on our consolidated financial position, results of operations or liquidity in any given year.
The Department of Environmental Protection of the Commonwealth of Pennsylvania (“PADEP”) advised B&W in March 1994 that it would seek monetary sanctions and remedial and monitoring relief related to the Parks Facilities. The relief sought related to potential groundwater contamination resulting from previous operations at the facilities. BWXT now owns these facilities. PADEP has advised BWXT that it does not intend to assess any monetary sanctions, provided that BWXT continues its remediation program for the Parks Facilities. Whether additional nonradiation contamination remediation will be required at the Parks facility remains unclear. Results from sampling completed by BWXT have indicated that such remediation may not be necessary. BWXT continues to evaluate closure of the groundwater issues pursuant to Pennsylvania’s Act II.
We perform significant amounts of work for the U.S. Government under both prime contracts and subcontracts and operate certain facilities that are licensed to possess and process special nuclear materials. As a result of these activities, we are subject to continuing reviews by governmental agencies, including the Environmental Protection Agency and the NRC.
The NRC’s decommissioning regulations requires BWXT to provide financial assurance that it will be able to pay the expected cost of decommissioning their facilities at the end of its service lives. BWXT will continue to provide financial assurance aggregating $24.5 million during the year ending December 31, 2007 with existing letters of credit for the ultimate decommissioning of all their licensed facilities, except one. This facility, which represents the largest portion of BWXT’s eventual decommissioning costs, has provisions in its government contracts pursuant to which all of its decommissioning costs and financial assurance obligations are covered by the DOE.
At December 31, 2006 and 2005, we had total environmental reserves (including provisions for the facilities discussed above) of $18.6 million and $14.9 million, respectively. Of our total environmental reserves at December 31, 2006 and 2005, $9.6 million and $5.8 million, respectively, were included in current liabilities. Inherent in the estimates of those reserves and recoveries are our expectations regarding the levels of contamination, decommissioning costs and recoverability from other parties, which may vary significantly as decommissioning activities progress. Accordingly, changes in estimates could result in material adjustments to our operating results, and the ultimate loss may differ materially from the amounts we have provided for in our consolidated financial statements.
Operating Leases
Future minimum payments required under operating leases that have initial or remaining noncancellable lease terms in excess of one year at December 31, 2006 are as follows (in thousands):
Total rental expense for the years ended December 31, 2006, 2005 and 2004 was $52.0 million, $33.1 million and $49.0 million, respectively. These expense amounts include contingent rentals and are net of sublease income, neither of which is material.
Other
One of B&W’s Canadian subsidiaries has received notice of a possible warranty claim on one of its projects on a contract executed in 1998. This project included a limited-term performance bond totaling approximately $140
million for which MII entered into an indemnity arrangement with the surety underwriters. At this time, B&W’s subsidiary continues to analyze the facts and circumstances surrounding this issue. It is possible that B&W’s subsidiary may incur warranty costs in excess of amounts provided for as of December 31, 2006. It is also possible that a claim could be initiated by the B&W subsidiary’s customer against the surety underwriter should certain events occur. If such a claim were successful, the surety could seek to recover from B&W’s subsidiary the costs incurred in satisfying the customer claim. If the surety seeks recovery from B&W’s subsidiary, we believe that B&W’s subsidiary would have adequate liquidity to satisfy its obligations. However, the ultimate resolution of this possible claim is uncertain, and an adverse outcome could have a material adverse impact on our consolidated financial position, results of operations and cash flows.
We have been advised by the Internal Revenue Service (“IRS”) of potential proposed unfavorable tax adjustments related to the 2001 through 2003 tax years. We have reviewed the IRS positions and disagree with certain proposed adjustments. Accordingly, we have filed a protest with the IRS regarding the resolution of these issues. We have provided for amounts that we believe will be ultimately payable under the proposed adjustments; however, these proposed IRS adjustments, should they be sustained, would result in a tax liability of approximately $25 million in excess of amounts provided for in our consolidated financial statements. In addition to this IRS matter, refer to Note 12 for information on the potential uncertainties associated with our reorganization of the MI and JRMH U.S. tax groups.
NOTE 11 - RELATED-PARTY TRANSACTIONS
We are a large business organization with worldwide operations, and we engage in numerous purchase, sale and other transactions annually. We have various types of business arrangements with corporations and other organizations in which an executive officer, director or nominee for director may also be a director, executive or investor, or have some other direct or indirect relationship. We enter into these arrangements in the ordinary course of our business, and they typically involve us receiving or providing some good or service on a nonexclusive basis and at arm’s-length negotiated rates or in accordance with regulated price schedules.
Each of Messrs. Wilkinson, Easter, Kalman, Nesser and Sannino has irrevocably elected to satisfy withholding obligations relating to all or a portion of any applicable federal, state or other taxes that may be due on the vesting in the year ending December 31, 2007 of certain shares of restricted stock awarded under various long-term incentive plans by returning to us the number of such vested shares having a fair market value equal to the amount of such taxes. These elections, which apply to an aggregate of 75,000, 12,000, 60,000, 31,500 and 24,000 shares vesting in the year ending December 31, 2007 and held by Messrs. Wilkinson, Easter, Kalman, Nesser and Sannino, respectively, are subject to approval of the Compensation Committee of our Board of Directors, which approval was granted. In the year ended December 31, 2006, each of Messrs. Wilkinson, Kalman, Nesser and Sannino made a similar election which applied to an aggregate of 82,500, 7,500, 42,750 and 27,525 shares, respectively, that vested in the year ended December 31, 2006. Those elections were also approved by the Compensation Committee. We expect any transfers reflecting shares of restricted stock returned to us will be reported in the SEC filings made by those transferring holders who are obligated to report transactions in our securities under Section 16 of the Securities Exchange Act of 1934.
See Note 3 for additional transactions with unconsolidated affiliates.
NOTE 12 - RISKS AND UNCERTAINTIES
As of December 31, 2006, in accordance with the percentage-of-completion method of accounting, we have provided for our estimated costs to complete all of our ongoing contracts. However, it is possible that current estimates could change due to unforeseen events, which could result in adjustments to overall contract costs. The risk on fixed-priced contracts is that revenue from the customer does not rise to cover increases in our costs. It is possible that current estimates could materially change for various reasons, including, but not limited to, fluctuations in forecasted labor productivity, pipeline lay rates or steel and other raw material prices. Increases in costs on our fixed-price contracts could have a material adverse impact on our consolidated results of operations, financial condition and cash flows. Alternatively, reductions in overall contract costs at completion could materially improve our consolidated results of operations, financial condition and cash flows.
At December 31, 2006, JRM had approximately $28 million in accounts and notes receivable due from its former joint venture in Mexico. A note receivable is attributable to the sale of JRM’s DB17 vessel during the quarter
ended September 30, 2004. This joint venture has experienced liquidity problems. Recognition of a gain of approximately $5.4 million on the sale of the DB17 is currently being deferred. On October 17, 2006, JRM reached an agreement with its partner and terminated JRM’s interest in this joint venture. The financial impact of this transaction is included in our consolidated results of operations. JRM expects to collect all net accounts and notes receivable currently owed from this joint venture. In the year ended December 31, 2006, JRM recorded an impairment loss totaling approximately $16.4 million attributable to currency translation losses recorded in accumulated other comprehensive loss.
In June 2006, B&W was awarded separate contracts to supply eight supercritical, coal-fired boilers and selective catalytic reduction (“SCR”) systems as part of TXU Corp.’s solid-fuel power generation program in Texas. The expected revenues from these awards exceeded $1 billion. B&W’s backlog at June 30, 2006 and September 30, 2006 reflected all the TXU awards. B&W has received notice from TXU to suspend activity on five of the eight boilers and SCR systems. The notifications did not specify the length of the suspensions. The notifications obligate B&W to suspend performance on these five units. The suspension provisions allow B&W reimbursement of suspension cost and equitable adjustment to the price, schedule and other relevant terms of the contract. Additionally, on February 26, 2007, TXU issued a press release and conducted an investor conference call relating to a proposed buyout transaction involving TXU announced on that date. In the investor conference call, representatives of TXU indicated that it is reducing planned coal-fueled generation units in Texas from eleven to three and that the permitting process for the eight units to be provided by B&W will be suspended. Because we have received no cancellation notices from TXU, we have continued to work on the three remaining units which were not suspended; however, we have excluded the TXU award for the eight units from our ending backlog at December 31, 2006.
The reorganization of the MI and JRMH U.S. tax groups, which was completed on December 31, 2006, resulted in a material, favorable impact on our consolidated financial results for the year ended December 31, 2006. Although we believe that the tax result of the reorganization as reported in our consolidated financial statements is accurate, the tax results derived will likely be subject to audit, or other challenge, by the IRS. Should the IRS’ interpretation of the tax law in this regard differ from our interpretation and that of our outside tax advisors, such that adjustments are proposed or sustained by the IRS, there could be a material adverse effect on our consolidated financial results as reported and our expected future cash flows.
NOTE 13 - FINANCIAL INSTRUMENTS WITH CONCENTRATIONS OF CREDIT RISK
Our Offshore Oil and Gas Construction segment’s principal customers are businesses in the offshore oil, natural gas and hydrocarbon processing industries and other offshore construction companies. The primary customer of our Government Operations segment is the U.S. Government (including its contractors). Our Power Generation Systems segment’s major customers are large utilities. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic or other conditions. In addition, we and many of our customers operate worldwide and are therefore exposed to risks associated with the economic and political forces of various countries and geographic areas. Approximately 43% of our trade receivables are due from foreign customers. See Note 17 for additional information about our operations in different geographic areas. We generally do not obtain any collateral for our receivables.
We believe that our provision for possible losses on uncollectible accounts receivable is adequate for our credit loss exposure. At December 31, 2006 and 2005, the allowance for possible losses we deducted from accounts receivable-trade on the accompanying balance sheet was $4.1 million and $0.2 million, respectively.
NOTE 14 - INVESTMENTS
The following is a summary of our available-for-sale securities at December 31, 2006:
(1)
Fair value of $36.0 million pledged to secure payments under certain reinsurance agreements.
The following is a summary of our available-for-sale securities at December 31, 2005:
(1)
Fair value of $41.4 million pledged to secure payments under certain reinsurance agreements.
At December 31, 2006, all our available-for-sale debt securities have contractual maturities primarily between 2007 and 2010.
Proceeds, gross realized gains and gross realized losses on sales of available-for-sale securities were as follows:
NOTE 15 - DERIVATIVE FINANCIAL INSTRUMENTS
Our worldwide operations give rise to exposure to market risks from changes in foreign exchange rates. We use derivative financial instruments to reduce the impact of changes in foreign exchange rates on our operating results. We use these instruments primarily to hedge our exposure associated with revenues or costs on our long-term contracts that are denominated in currencies other than our operating entities’ functional currencies. We do not hold or issue financial instruments for trading or other speculative purposes.
We enter into derivative financial instruments primarily as hedges of certain firm purchase and sale commitments denominated in foreign currencies. We record these contracts at fair value on our consolidated balance sheets. Depending on the hedge designation at the inception of the contract, the related gains and losses on these contracts are either deferred in stockholders’ equity (deficit) (as a component of accumulated other comprehensive loss) until the hedged item is recognized in earnings or offset against the change in fair value of the hedged firm commitment through earnings. The ineffective portion of a derivative’s change in fair value and any portion excluded from the assessment of effectiveness are immediately recognized in earnings. The gain or loss on a derivative instrument not designated as a hedging instrument is also immediately recognized in earnings. Gains and losses on derivative financial instruments that require immediate recognition are included as a component of other income (expense)-net in our consolidated statements of income.
At December 31, 2006, we had forward contracts to purchase $211.1 million in foreign currencies (primarily Euro and Canadian Dollars) at varying maturities through September 2009. At December 31, 2005, we had forward contracts to purchase $67.3 million in foreign currencies (primarily Euro) at varying maturities. At December 31, 2006, we also had a foreign currency option contracts outstanding to purchase 1.3 million Euros at a strike price of 1.30 with varying expiration dates extending to October 31, 2007. Also at December 31, 2006, we had a foreign currency option contract to purchase 1.5 million Chinese Renminbi at a strike price of 8.0316 with an expiration date of August 30, 2007. We have designated substantially all of these contracts as cash flow hedging instruments. For the option contracts, the hedged risk is the risk of changes in forecasted U.S. dollar equivalent cash flows related to long-term contracts attributable to movements in the exchange rate above the strike prices. We assess effectiveness based upon total changes in cash flows of the option contracts. For forward contracts, the hedged risk is the risk of changes in functional-currency-equivalent cash flows attributable to changes in spot exchange rates of forecasted transactions related to long-term contracts. We exclude from our assessment of effectiveness the portion of the fair value of the forward contracts attributable to the difference between spot exchange rates and forward exchange rates. At December 31, 2006 and 2005, we have deferred approximately $9.4 million and ($0.9) million, respectively, of net gains (losses) on these derivative financial instruments. Of the deferred amount at December 31, 2006, we expect to recognize substantially all of it in income over the next 12 months, primarily in accordance with the percentage-of-completion method of accounting. For the years ended December 31, 2006, 2005 and 2004, we immediately recognized net gains (losses) of approximately ($4.1) million, ($0.2) million and $0.5 million, respectively. Substantially all of these net gains represent changes in the fair value of forward contracts excluded from hedge effectiveness.
We are exposed to credit-related losses in the event of nonperformance by counterparties to derivative financial instruments. We mitigate this risk by using major financial institutions with high credit ratings.
NOTE 16 - FAIR VALUES OF FINANCIAL INSTRUMENTS
We used the following methods and assumptions in estimating our fair value disclosures for financial instruments:
Cash and cash equivalents and restricted cash and cash equivalents: The carrying amounts we have reported in the accompanying consolidated balance sheets for cash and cash equivalents approximate their fair values.
Investments: We estimate the fair values of investments based on quoted market prices. For investments for which there are no quoted market prices, we derive fair values from available yield curves for investments of similar quality and terms.
Long- and short-term debt: We base the fair values of debt instruments on quoted market prices. Where quoted prices are not available, we base the fair values on the present value of future cash flows discounted at estimated borrowing rates for similar debt instruments or on estimated prices based on current yields for debt issues of similar quality and terms.
Foreign currency derivative instruments: We estimate the fair values of foreign currency option contracts and forward contracts by obtaining quoted market rates. At December 31, 2006, we had net forward contracts outstanding to purchase foreign currencies, primarily Euro and Canadian Dollars, with a total notional value of $211.1 million and a total fair value of $1.6 million.
The estimated fair values of our financial instruments are as follows:
NOTE 17 - SEGMENT REPORTING
Our reportable segments are Offshore Oil and Gas Construction, Government Operations and Power Generation Systems. The operations of our segments are managed separately and each has unique technology, services and customer class.
Offshore Oil and Gas Construction, which includes the results of JRM, supplies worldwide services for the offshore oil and gas exploration, production and hydrocarbon processing industries and to other offshore construction companies. Principal activities include the design, engineering, fabrication and installation of offshore drilling and production platforms, specialized structures, modular facilities, marine pipelines and subsea production systems. JRM also provides project management services, engineering services and procurement activities.
Government Operations supplies nuclear components to the U.S. Government, manages and operates government-owned facilities and supplies commercial nuclear environmental services and other government and commercial nuclear services. Government Operations also includes contract research activities. The Government Operations segment’s operations are conducted through BWXT.
Power Generation Systems supplies engineered-to-order services, products and systems for energy conversion, and fabricates replacement nuclear steam generators and environmental control systems. In addition, this segment provides aftermarket and other services, including replacement parts, engineered upgrades, construction, maintenance and field technical services to electric power plants and industrial facilities. This segment also provides power through cogeneration, refuse-fueled power plants and other independent power producing facilities. The Power Generation Systems segment’s operations are conducted primarily through B&W, which was not consolidated during the years ended December 31, 2005 and 2004 due to B&W’s Chapter 11 proceedings. We reconsolidated the results of B&W when B&W emerged from bankruptcy, effective February 22, 2006. Our Power Generation Systems segment for the year ended December 31, 2006 includes approximately ten months (March through December 2006) of results attributable to B&W. The years ended December 31, 2005 and 2004 do not include any results attributable to B&W. See Note 20 for information on B&W and its subsidiaries.
We account for intersegment sales at prices that we generally establish by reference to similar transactions with unaffiliated customers. Reportable segments are measured based on operating income exclusive of general corporate expenses, contract and insurance claims provisions, legal expenses and gains (losses) on sales of corporate assets. Other reconciling items to income from continuing operations before provision for income taxes are interest income, interest expense, minority interest and other income (expense)-net. We exclude prepaid pension costs from segment assets.
SEGMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004.
1. Information about Operations in our Different Industry Segments:
(1)
Segment revenues are net of the following intersegment transfers and other adjustments:
2. Information about our Product and Service Lines:
3. Information about our Operations in Different Geographic Areas:
(1)
We allocate geographic revenues based on the location of the customer.
4. Information about our Major Customers:
In the years ended December 31, 2006, 2005 and 2004, the U.S. Government accounted for approximately 15%, 31% and 27%, respectively, of our total revenues. We have included these revenues in our Government Operations segment. In the year ended December 31, 2005, revenue from a distinct customer of our Offshore Oil and Gas Construction segment was $369.6 million and represented 20% of our total revenues. In the year ended December 31, 2004, revenues from two distinct customers of our Offshore Oil and Gas Construction segment accounted for $424.5 million and $274.9 million, respectively, and represented 22% and 14%, respectively, of our total revenues.
NOTE 18 - QUARTERLY FINANCIAL DATA (UNAUDITED)
The following tables set forth selected unaudited quarterly financial information for the years ended December 31, 2006 and 2005:
(1)
Includes equity in income from investees.
Results for the quarter ended June 30, 2006 includes the impact of the expense related to the early retirement of JRM secured notes totaling approximately $49.0 million. Results for the quarter ended December 31, 2006 included the impact of the reversal of a federal deferred tax valuation allowance adjustment totaling approximately $94.1 million. See Notes 5 and 4, respectively.
(1)
Includes equity in income from investees.
Results for the quarter ended June 30, 2005 included the impact of the reversal of a federal deferred tax valuation allowance adjustment totaling approximately $50.4 million. See Note 4.
Quarterly results for the year ended December 31, 2005 include income or expense for the revaluation of certain components of the estimated settlement cost related to the B&W Chapter 11 proceedings, as follows:
NOTE 19 - EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings per share:
NOTE 20 - THE BABCOCK & WILCOX COMPANY
General
As a result of asbestos-containing commercial and utility boilers and other products B&W and certain of its subsidiaries sold, installed or serviced in prior decades, B&W was subject to a substantial volume of nonemployee liability claims asserting asbestos-related injuries. All of the personal injury claims were similar in nature, the primary difference being the type of alleged injury or illness suffered by the plaintiff as a result of the exposure to asbestos fibers (e.g., mesothelioma, lung cancer and other types of cancer, asbestosis or pleural changes).
On February 22, 2000, B&W and certain of its subsidiaries filed a voluntary petition in the U.S. Bankruptcy Court for the Eastern District of Louisiana (the “Bankruptcy Court”) in New Orleans to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Included in the filing were B&W and its subsidiaries, Americon, Inc., Babcock & Wilcox Construction Co., Inc. and Diamond Power International, Inc. (collectively with B&W, the “Debtors”). The Debtors took this action as a means to determine and comprehensively resolve all pending and future asbestos liability claims against them. On February 22, 2006, the Debtors emerged from Chapter 11.
Plan of Reorganization
During the course of the B&W Chapter 11 proceedings, we engaged in settlement negotiations with the Asbestos Claimants Committee (“ACC”) and the Legal Representative for Future Asbestos-Related Claimants (the “Future Claimants Representative” or the “FCR”). Those discussions led to a settlement (the “Settlement”), which was embodied in a plan of reorganization and related settlement agreement, which we and the other plan proponents jointly filed with the Bankruptcy Court on September 29, 2005 (the “plan of reorganization”). The plan of reorganization was confirmed on January 17, 2006 by the United States District Court for the Eastern District of Louisiana, was approved by our shareholders on January 18, 2006 and became effective February 22, 2006.
Under the terms of the plan of reorganization, MII and all of its subsidiaries, including its captive insurers, and all of their respective directors and officers, received the full benefit of the protections afforded by Section 524(g) of the Bankruptcy Code with respect to asbestos-related personal injury claims (other than workers’ compensation claims) attributable to the business or operations of B&W or any of its subsidiaries and that are subject to the jurisdiction of courts in the United States.
The plan of reorganization provided for a trust created for the benefit of asbestos personal injury claimants (the “Trust”). On February 22, 2006, B&W paid $350 million to the Trust. On December 21, 2006, MI paid an additional $355 million to the Trust. As part of the B&W Chapter 11 plan of reorganization, B&W also issued a promissory note to the Trust in the aggregate principal amount of $250 million payable, subject to specified contingencies, on December 1, 2006. On November 30, 2006, B&W borrowed $250 million as a term loan under the B&W Facility and paid the $250 million to the Trust on December 1, 2006. See Note 5 for additional information on the B&W Facility. As of December 31, 2006, all financial obligations under the B&W Chapter 11 plan of reorganization were satisfied.
We expect these contributions made to the Trust should be tax deductible for the purpose of MI’s consolidated U.S. tax return, except to the extent such contributions consist of insurance proceeds or the transfer of rights under insurance policies.
As part of the settlement process, the Trust is also entitled to the proceeds of certain insurance policies that cover, among other things, asbestos claims, which policies have an aggregate face value of available limits of coverage of approximately $1.15 billion.
The plan of reorganization did not impair the claims against B&W for nuclear-related injuries allegedly arising from the operation of the nuclear-fuel processing facilities in Apollo and Parks Township, including the claims asserted in the Hall Litigation (the “Apollo/Parks Township Claims”), which were permitted to pass through the bankruptcy proceeding unaffected by it. See Note 10 for additional information regarding the Hall Litigation.
Accounting Treatment
As a result of the Chapter 11 filing, beginning on February 22, 2000, we stopped consolidating the results of operations of B&W and its subsidiaries in our financial statements, and we began accounting for our investment in B&W under the cost method. The Chapter 11 filing, along with subsequent filings and negotiations, led to increased uncertainty with respect to the amounts, means and timing of the ultimate settlement of asbestos claims and the recovery of our investment in B&W. Due to this increased uncertainty, we wrote off our net investment in B&W in the quarter ended June 30, 2002. The total impairment charge of $224.7 million included our investment in B&W of $187.0 million and other related assets totaling $37.7 million.
On December 19, 2002, in connection with the filing of documentation in the Chapter 11 proceedings relating to a previously proposed settlement, we determined that a liability related to that proposed settlement was probable and that the amount of that liability was reasonably estimable. Accordingly, as of December 31, 2002, we established an estimate for the cost of settlement of $110 million, including tax expense of $23.6 million, reflecting the present value of our contemplated contributions to the trusts. This estimate had been adjusted since 2002 through June 30, 2005 based on the provisions of the previously proposed settlement, and a liability of $146.7 million was recorded at June 30, 2005. This liability remained frozen through the date B&W emerged from Chapter 11. (See discussion below.)
Under the terms of the Settlement and the plan of reorganization, MI was allowed to maintain its equity in B&W and reconsolidate B&W’s operations as of February 22, 2006. Based on the Settlement and the plan of reorganization and the fact that we reacquired control of B&W, we accounted for the difference between the carrying amount of our investment in B&W and B&W’s net assets in a manner similar to a step acquisition. Our investment in B&W consists of the previously proposed settlement liability disclosed above totaling $146.7 million and certain other liabilities and adjustments related to the B&W Chapter 11 proceedings totaling $60.5 million, bringing our total investment basis in B&W to a negative $207.2 million. The net asset basis of B&W reconsolidated at February 22, 2006 totaled a negative $186.3 million. As a result, we had a basis differential between our investment basis in B&W and the net assets reconsolidated totaling a negative $20.9 million. We have accounted for this basis difference as negative goodwill and have reduced our consolidated goodwill relating to B&W accordingly in the reconsolidation.
Financial Results and Reorganization Items
We have included the results of B&W effective from February 22, 2006 in our consolidated financial statements. In the year ended December 31, 2006, we have included the following for B&W in our consolidated financial statements (in thousands):
The pro forma information below presents combined results of operations as if B&W and MII had been reconsolidated at the beginning of the respective periods presented. This pro forma information is not necessarily indicative of the results of operations of the combined entities had the combination occurred at the beginning of the periods presented, nor is it indicative of future results.
NOTE 21 - RESTRICTED CASH
At December 31, 2006, we had restricted cash and cash equivalents totaling $106.7 million, of which $17.6 million is required to meet reinsurance reserve requirements of our captive insurance companies and $89.1 million is held in restricted foreign accounts.
Item 9.
Item 9.
CHANGES IN AND DISAGREEMENTS WITH AUDITORS ON ACCOUNTING AND FINANCIAL DISCLOSURE
For the year ended December 31, 2006, we had no disagreements with Deloitte & Touche LLP on any accounting or financial disclosure issues. For the years ended December 31, 2005 and 2004, we had no disagreements with PricewaterhouseCoopers LLP on any accounting or financial disclosure issues.
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As of the end of the period covered by this annual report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as that term is defined in Rules 13a-15(e) and 15d-15(e) adopted by the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Our disclosure controls and procedures were developed through a process in which our management applied its judgment in assessing the costs and benefits of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding the control objectives. You should note that the design of any system of disclosure controls and procedures is based in part upon various assumptions about the likelihood of future events, and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote. Based on the evaluation referred to above, our Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of our disclosure controls
and procedures are effective as of December 31, 2006 to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and forms and such information is accumulated and communicated to management as appropriate to allow timely decisions regarding disclosure.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as that term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) and for our assessment of the effectiveness of internal control over financial reporting.
Our internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our consolidated financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of our management and Board of Directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006, based on the framework established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). This assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of those controls. Based on our assessment under the criteria described above, management has concluded that our internal control over financial reporting was effective as of December 31, 2006.
Management’s assessment of the effectiveness of our internal control over financial reporting has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which appears in this report.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the year ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of McDermott International, Inc.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that McDermott International, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the Company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also, in our opinion, the Company maintained in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2006 of the Company and our report dated March 1, 2007 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules and included an explanatory paragraph regarding the emergence of a wholly owned subsidiary of the Company from Chapter 11 of the U.S. Bankruptcy Code.
DELOITTE & TOUCHE LLP
Houston, Texas
March 1, 2007
Item 9B.
Item 9B. OTHER INFORMATION
None.
PART III
Item 10.
Item 10. DIRECTOR, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item with respect to directors and executive officers is incorporated by reference to the material appearing under the headings “Election of Directors,” “Executive Officers” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement for our 2007 Annual Meeting of Stockholders. The information required by this item with respect to “audit committee financial experts” is incorporated by reference to the last paragraph appearing in the “Audit Committee” section under the heading “Corporate Governance - Board of Directors and Its Committees” in the Proxy Statement for our 2007 Annual Meeting of Stockholders.
Item 11.
Item 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference to the material appearing under the headings “Compensation Discussion and Analysis,” “Compensation of Directors,” “Compensation of Executive Officers,”
“Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the Proxy Statement for our 2007 Annual Meeting of Stockholders.
Item 12.
Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item is incorporated by reference to (1) the Equity Compensation Plan Information table appearing in Item 5 - “Market for the Registrant’s Common Equity and Related Stockholder Matters” in Part II of this report and (2) the material appearing under the headings “Security Ownership of Directors and Executive Officers” and “Security Ownership of Certain Beneficial Owners” in the Proxy Statement for our 2007 Annual Meeting of Stockholders.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE
The information in Note 11 to our consolidated financial statements included in this report is incorporated by reference.
Item 14.
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item is incorporated by reference to the material appearing under the heading “Ratification of Appointment of Independent Registered Public Accounting Firm for Year Ending December 31, 2007” in the Proxy Statement for our 2007 Annual Meeting of Stockholders.
PART IV
Item 15.
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this Annual Report or incorporated by reference:
1. CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2006 and 2005
Consolidated Statements of Income for the Years Ended December 31, 2006, 2005 and 2004
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004
Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2006, 2005 and 2004
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
Notes to Consolidated Financial Statements for the Years Ended December 31, 2006, 2005 and 2004
2. CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
Schedules II and V are filed with this report. All other schedules, except for Schedule I, which will be filed on Form 10-K/A, for which provision is made of the applicable regulations of the SEC have been omitted because they are not required under the relevant instructions or because the required information is included in the financial statements or the related footnotes contained in this report.
3. EXHIBITS
*
Management contract or compensatory plan or arrangement.
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.
McDERMOTT INTERNATIONAL, INC.
/s/ Bruce W. Wilkinson
March 1, 2007
By:
Bruce W. Wilkinson
Chairman of the Board and
Chief Executive Officer
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 indicated and on the date indicated.
Signature
Title
/s/ Bruce W. Wilkinson
Bruce W. Wilkinson
Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)
/s/ Francis S. Kalman
Francis S. Kalman
Executive Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Representative)
/s/ Michael S. Taff
Michael S. Taff
Vice President and Chief Accounting Officer (Principal Accounting Officer and Duly Authorized Representative)
/s/ John F. Bookout, III
John F. Bookout, III
Director
/s/ Roger A. Brown
Roger A. Brown
Director
/s/ Ronald C. Cambre
Ronald C. Cambre
Director
/s/ Bruce DeMars
Bruce DeMars
Director
/s/ Robert W. Goldman
Robert W. Goldman
Director
/s/ Robert L. Howard
Robert L. Howard
Director
/s/ Oliver D. Kingsley, Jr.
Oliver D. Kingsley, Jr.
Director
/s/ D. Bradley McWilliams
D. Bradley McWilliams
Director
/s/ Thomas C. Schievelbein
Thomas C. Schievelbein
Director
March 1, 2007
Schedule II
McDERMOTT INTERNATIONAL, INC.
VALUATION AND QUALIFYING ACCOUNTS
(1)
Estimated drydock liability is reported within accrued liabilities-other and other liabilities on the balance sheet.
(2)
Net of reductions and other adjustments, all of which are charged to costs and expenses.
(3)
Cash payment of drydock costs.
(4)
Amounts charged to other accounts included in other comprehensive income (minimum pension liability).
Schedule V
McDERMOTT INTERNATIONAL, INC.
SUPPLEMENTARY INFORMATION CONCERNING PROPERTY-CASUALTY INSURANCE OPERATIONS
(In thousands)
Consolidated Property-Casualty Entities
INDEX TO EXHIBITS