form10k.htm

INDEX - FORM 10-K

PART I

			PAGE
Item 1.	BUSINESS
	A.	General	1

	B.	Offshore Oil and Gas Construction	2
		General	2
		Vessels and Properties	3
		Joint Ventures	4
		Foreign Operations	5
		Customers	5
		Contracts	5
		Backlog	6
		Raw Materials	6
		Competition	6
		Factors Affecting Demand	7

	C.	Government Operations	7
		General	7
		Properties	7
		Operations	8
		Customers	10
		Contracts	10
		Backlog	11
		Raw Materials	11
		Competition	11
		Factors Affecting Demand	11

	D.	Power Generation Systems	12
		General	12
		Properties	12
		Operations	13
		Customers	14
		Contracts	14
		Backlog	15
		Raw Materials	15
		Competition	15
		Factors Affecting Demand	16

	E.	Patents and Licenses	16

	F.	Research and Development Activities	16

	G.	Insurance	16

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	H.	Employees	18

	I.	Governmental Regulations and Environmental Matters	18

	J.	Cautionary Statement Concerning Forward-Looking Statements	20

	K.	Available Information	22

Item 1A.	RISK FACTORS		22

Item 1B.	UNRESOLVED STAFF COMMENTS		28

Item 2.	PROPERTIES		28

Item 3.	LEGAL PROCEEDINGS		28

Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		28

P A R T I I

Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	28

Item 6.	SELECTED FINANCIAL DATA	31

Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	32
	General	32
	Critical Accounting Policies and Estimates	34
	Year Ended December 31, 2007 Compared to Year Ended December 31, 2006	37
	Year Ended December 31, 2006 Compared to Year Ended December 31, 2005	40
	Effects of Inflation and Changing Prices	44
	Liquidity and Capital Resources	44

Item 7A.	QUANTITATIVE AND QUALITATIVE DISLCOSURES ABOUT MARKET RISK	50

Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Report of Independent Registered Public Accounting Firm	52
	Consolidated Balance Sheets – December 31, 2007 and December 31, 2006	55
	Consolidated Statements of Income for the Years Ended December 31, 2007, 2006 and 2005	57
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005	58
	Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2007, 2006 and 2005	59
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005	60

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	Notes to Consolidated Financial Statements	61

Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	107

Item 9A.	CONTROLS AND PROCEDURES
	Disclosure Controls and Procedures	107
	Management’s Report on Internal Control Over Financial Reporting	108
	Changes in Internal Control Over Financial Reporting	108
	Report of Independent Registered Public Accounting Firm	108

Item 9B.	OTHER INFORMATION	109

PART III

Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	110

Item 11.	EXECUTIVE COMPENSATION	110

Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	111

Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	111

Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	111

PART IV

Item 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	111

Signatures		117
Third Amendment to Revolving Credit Agreement
First Amendment to Credit Agreement and Limited Waiver to Mortgages
Second Amendment to Credit Agreement
2008 Performance Shares Grant Agreement
2008 Restricted Stock Grant Agreement
Ratio of Earnings to Fixed Charges
Significant Subsidiaries
Consent of PricewaterhouseCoopers LLP
Consent of Deloitte & Touche LLP
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
Section 1350 Certification of Chief Executive Officer
Section 1350 Certification of Chief Financial Officer

iii

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Statements we make in this Annual Report on Form 10-K which express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the headings “Cautionary Statement Concerning Forward-Looking Statements” and “Risk Factors” in Items 1 and 1A of Part I of this report.

PART I

Item 1. BUSINESS

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, including J. Ray McDermott, S.A. (“JRMSA”) and The Babcock & Wilcox Company (“B&W”). In this Annual Report on Form 10-K, unless the context otherwise indicates, “we,” “us” and “our” mean MII and its consolidated subsidiaries.

We operate in three business segments: Offshore Oil and Gas Construction, Government Operations and Power Generation Systems.

During 2007, we renamed, and in some cases restructured, many of the principal operating companies within our Government Operations and Power Generation Systems segments. One of the renamed companies, Babcock & Wilcox Power Generation Group, Inc. (“B&W PGG”), was previously named The Babcock & Wilcox Company. See the segment description below for the new names of the other principal operating companies. In addition, we changed the name of the parent company of our Government Operations and Power Generation Systems subsidiaries to The Babcock & Wilcox Company. As a result, The Babcock & Wilcox Company now refers to the parent company of our subsidiaries comprising our Government Operations and Power Generation Systems segments. As used in this Annual Report on Form 10-K, the term B&W is a reference to the renamed The Babcock & Wilcox Company.

Our business segments are outlined as follows:

Offshore Oil and Gas Construction includes the business and operations of JRMSA, J. Ray McDermott Holdings, LLC and their respective subsidiaries. This segment supplies services primarily to offshore oil and gas field developments worldwide, including 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, including the United States, Mexico, Canada, the Middle East, India, the Caspian Sea and Asia Pacific.

Government Operations includes the business and operations of BWX Technologies, Inc., Babcock & Wilcox Nuclear Operations Group, Inc., Babcock & Wilcox Technical Services Group, Inc. and their respective 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”).

Power Generation Systems includes the business and operations of B&W PGG, Babcock & Wilcox Nuclear Power Generation Group, Inc. and their respective subsidiaries. This segment supplies fossil-fired steam generating systems, replacement commercial nuclear steam generators, environmental equipment and components, and related services to customers around the world. It designs, engineers, manufactures 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. On February 22, 2006, B&W PGG and three of its subsidiaries exited from their asbestos-related Chapter 11 Bankruptcy proceedings (the “Chapter 11 Bankruptcy”), which were commenced on February 22, 2000.

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Due to the Chapter 11 Bankruptcy, we did not consolidate the results of operations of these entities in our consolidated financial statements from February 22, 2000 through February 22, 2006.

The following tables summarize our revenues and operating income by business segment for the years ended December 31, 2007, 2006 and 2005. See Note 18 to our consolidated financial statements included in this report for additional information about our business segments and operations in different geographic areas.

	Year Ended December 31,
	2007			2006(1)			2005(1)
	(In millions)
REVENUES:

Offshore Oil and Gas Construction	$	2,445.7		$	1,610.3		$	1,238.9
Government Operations		694.0			630.1			601.0
Power Generation Systems		2,504.2			1,888.6			-
Adjustments and Eliminations		(12.3	)		(8.9	)		(0.2	)
	$	5,631.6		$	4,120.1		$	1,839.7

OPERATING INCOME:

Segment Operating Income (Loss):
Offshore Oil and Gas Construction	$	397.6		$	214.1		$	157.5
Government Operations		90.0			82.7			68.0
Power Generation Systems		219.7			101.9			(0.9	)
	$	707.3		$	398.7		$	224.6

Gain (Loss) on Asset Disposals
and Impairments – Net:
Offshore Oil and Gas Construction	$	6.8		$	(16.2	)	$	6.4
Government Operations		1.6			1.1			0.1
Power Generation Systems		-			0.1			-
	$	8.4		$	(15.0	)	$	6.5

Equity in Income (Loss) from Investees:
Offshore Oil and Gas Construction	$	(3.9	)	$	(2.9	)	$	2.8
Government Operations		31.3			27.8			31.3
Power Generation Systems		14.3			12.6			6.4
	$	41.7		$	37.5		$	40.5

Unallocated corporate		(41.2	)		(29.9	)		(39.9	)
	$	716.2		$	391.3		$	231.7
(1) Results for the principal operating subsidiaries of our Power Generation Systems segment were not consolidated in our financial statements from February 22, 2000 through February 22, 2006, due to the Chapter 11 Bankruptcy.

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, Canada, the Middle East, India, the Caspian Sea and Asia Pacific.

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Vessels and Properties

Through our Offshore Oil and Gas Construction segment, we operate a fleet of marine vessels used in major offshore construction. We currently own and operate one derrick vessel and six combination derrick-pipelaying vessels. We also operate a pipelay vessel and a dive support vessel owned by 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.

On July 27, 2007, we completed our acquisition of substantially all the assets of Secunda International Limited, including 14 harsh-weather, multi-functional vessels, with capabilities which include subsea construction, pipelay, cable lay and dive support, as well as its shore-based operations.

Seven of our owned and/or operated major construction vessels are self-propelled. 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, 2007 (except where otherwise noted, each of the vessels is owned and operated by us):

Location and Vessel Name	Vessel Type	Year Entered Service/ Upgraded	Maximum Derrick Lift (tons)	Maximum Pipe Diameter (inches)
UNITED STATES
DB 50 (1)	Pipelay/Derrick	1988	4,400	20
DB 16 (1)	Pipelay/Derrick	1967/2000	860	30
Thebaud Sea (1) (2)	Multi-Service Vessel	1999	—	—
MEXICO
Bold Endurance (1) (2)	Multi-Service Vessel	1979	—	—
MIDDLE EAST
DB 101	Semi-Submersible Derrick	1978/1984	3,500	—
DB 27	Pipelay/Derrick	1974/1984	2,400	60
DLB KP1	Pipelay/Derrick	1974	660	60
Agile (1) (2)	Multi-Service Vessel	1978	—	—
CASPIAN SEA
Israfil Husseinov (3)	Pipelay	1997/2003	—	60
Akademik Tofiq Ismayilov (1) (3)	Dive Support Vessel	1987/2005	—	—
ASIA PACIFIC
DB 30	Pipelay/Derrick	1975/1999	3,080	60
DB 26	Pipelay/Derrick	1975	900	60
Emerald Sea (1) (2)	Multi-Service Vessel	1996/2007	—	—
Intermac 600 (4)	Launch/Cargo Barge	1973	—	—
Intermac 650 (5)	Launch/Cargo Barge	1980/2006	—	—

(1)	Vessel with dynamic positioning capability
(2)	Vessel acquired from Secunda International Limited in July 2007
(3)	Operated by us and owned by a subdivision of the State Oil Company of the Azerbaijan Republic
(4)	The dimensions of this vessel are 500’ x 120’ x 33’
(5)	The overall dimensions of this vessel are 650’ x 170’ x 40’

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.

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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 first quarter of 2008. 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 our fabrication facilities at December 31, 2007 were as follows:

Morgan City, Louisiana	Years 2008-2048
Dubai (Jebel Ali), U.A.E.	Year 2015
Batam Island, Indonesia	Years 2024-2038
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.

Joint Ventures

Our Offshore Oil & Gas Construction segment participates in the ownership of several entities with third parties. We generally refer to these entities as “joint ventures,” and we account for our investments in them under the equity method of accounting. These entities include:

Deepwater Marine Technology LLC. We co-own this entity with Keppel FELS Ltd. This joint venture expands our services related to the solutions involving tension leg platforms (“TLPs”). A TLP is a vertically moored floating structure normally used for the offshore production of oil and gas and is particularly suited for water depth greater than 1,000 feet.

FloaTEC LLC. We co-own this entity with Keppel FELS Ltd. This joint venture designs, markets, procures and contracts floating production systems to the deepwater oil and gas industry. The deepwater solutions include TLPs, spars and production semi-submersibles. A significant part of this entity’s strategy is to build on the established presence, reputation and resources of its two owners.

Spars International, Inc. We co-own this entity with Technip S.A. This joint venture primarily enters into engineering, procurement, construction and installation customer contracts for spars. Spars are single-hull floating columns designed to support offshore drilling and production equipment and to store oil. This joint venture assists our Offshore Oil and Gas Construction segment in the development and deployment of deepwater spar solutions for the oil and gas industry. Spars International, Inc. installed the first offshore spar platform in the Gulf of Mexico in 1,930 feet of water in 1996.

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Foreign Operations

Our Offshore Oil and Gas Construction segment’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):

	Revenues					Segment Income
	Amount		Percent			Amount		Percent

Year ended December 31, 2007	$	2,170,596		39	%	$	413,666		55	%
Year ended December 31, 2006	$	1,378,339		33	%	$	217,181		52	%
Year ended December 31, 2005	$	1,051,547		57	%	$	208,034		77	%

See Note 18 to our consolidated financial statements included in this report for further information on the geographic distribution of our revenues.

Customers

Our Offshore Oil and Gas Construction segment’s customers are primarily oil and gas companies, including several foreign government-owned companies. This segment’s five largest customers, as a percentage of our total consolidated revenues, during the years ended December 31, 2007 and 2006 were as follows:

Year Ended December 31, 2007:
Azerbaijan International Operating Company	6.2	%
Shell Oil	5.0	%
Aramco Overseas Company BV	3.3	%
Woodside Energy Limited	3.1	%
Qatar Liquified Gas Company Limited II	2.6	%

Year Ended December 31, 2006:
Azerbaijan International Operating Company	8.5	%
Aramco Overseas Company BV	6.6	%
Dolphin Energy Limited	3.1	%
Ras Laffan Liquified Natural Gas Company Limited	1.9	%
Conoco Indonesia, Inc.	1.3	%

The level of engineering and construction services required by any one customer largely 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.

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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, 2007 and 2006, our Offshore Oil and Gas Construction segment’s backlog amounted to approximately $4.8 billion and $4.1 billion, respectively. This represents approximately 49% and 54% of our total consolidated backlog at December 31, 2007 and 2006, respectively. Of our December 31, 2007 backlog in this segment, we expect to recognize revenues as follows (in approximate millions):

	Amount
Quarter Ending:
March 31, 2008	$	730
June 30, 2008	$	900
September 30, 2008	$	860
December 31, 2008	$	510

Year Ending December 31, 2009	$	1,100

Thereafter	$	650

In addition to our expected revenue recognition from ending backlog at December 31, 2007, our Offshore Oil and Gas Construction segment also realizes revenues from orders received and completed in the same fiscal quarter.

Backlog is not a measure recognized by generally accepted accounting principles. It is possible that our methodology for determining backlog may not be comparable to methods used by other companies. We generally include expected revenue in our backlog when we receive written confirmation from our customers. It is possible that backlog may not be indicative of future results, and projects in our backlog may be cancelled, modified or otherwise altered by customers.

Because of the more conducive weather conditions in certain geographic regions, 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.

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

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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 costs whether or not they are operating. See the discussion in Item 1A, “Risk Factors,” for additional information on the competitive nature of the offshore oil and gas construction business.

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 in the regions we operate. Numerous factors influence these expenditures, including:

·	oil and gas prices, along with expectations about future prices;

·	the cost of exploring for, producing and delivering oil and gas;

·	the terms and conditions of offshore leases;

·	the discovery rates of new oil and gas reserves in offshore areas;

·	the ability of businesses in the oil and gas industry to raise capital; and

·	local and international political and economic conditions.

See Item 1A, “Risk Factors,” for further information on factors affecting demand.

C. GOVERNMENT OPERATIONS

General

Through our Government Operations 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. Principal areas of operation include:

·	providing precision manufactured nuclear components for U.S. Government defense programs;

·	managing and operating nuclear production facilities;

·	managing and operating environmental management sites;

·	managing spent nuclear fuel and transuranic waste for the DOE;

·	providing critical skills and resources for DOE sites; and

·	developing and deploying next generation technology in support of U.S. Government programs.

Properties

Our Government Operations segment’s principal manufacturing facilities are located in:

·	Lynchburg, Virginia;

·	Barberton, Ohio;

·	Euclid, Ohio; and

·	Mount Vernon, Indiana.

Each of these facilities is located on property we own.

The Lynchburg, Virginia facility, which is our Government Operations segment’s primary manufacturing plant, is the nation’s largest commercial high-enriched uranium processing facility. The facility resides on 437 acres with

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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:

·	advanced heat treatment to optimize material properties of components;

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;

·	the design and development of advanced nuclear fuels systems for space, defense, research and commercial applications; and

·	the production of aluminum-clad uranium fuel elements of high and low enrichments for research and test reactors.

The other manufacturing facilities for our Government Operations segment are the Barberton, Ohio, Euclid, 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 Euclid facility includes 26 acres with 240,000 square feet of manufacturing area and 90,000 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.

The Barberton, Euclid 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

We manage and operate complex, high-consequence nuclear and national security operations for the DOE and the National Nuclear Security Administration (“NNSA”), primarily through corporations, limited liability companies and partnerships, which we refer to as “joint ventures.” We account for our interests in some of these entities under the equity method of accounting. In addition, we provide a broad array of technical services in support of DOE and NNSA operations and facilities.

We provide operations, management and technical services in support of the following U.S. Government facilities:

Pantex Plant. Through Babcock & Wilcox Technical Services Pantex, L.L.C., which we co-own with Honeywell International Inc. and Bechtel National, Inc., we manage and operate the Pantex Plant. The Pantex Plant is located on 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.

Y-12 National Security Complex (“Y-12 Complex”). Through Babcock & Wilcox Technical Services Y-12, L.L.C, an entity we co-own with Bechtel National, Inc., we manage the Y-12 Complex. The Y-12 Complex is located on 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.

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Idaho National Laboratory. Through Bechtel BWXT Idaho, L.L.C., a limited liability corporation formed with Bechtel National, we manage the nuclear and national security operations of this site as a team member of the Battelle Energy Alliance, the operator of the site. 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. The site includes 52 facilities, of which 12 are classified as Hazard Category 2. A Hazard Category 2 designation is based on the quantities of radioactive materials at the facility and specified levels of radioactive/hazardous material released without mitigation.

Strategic Petroleum Reserve. Since 1993, this facility has been managed and operated by DynMcDermott Petroleum Operations Company, an entity we co-own with DynCorp International, International-Matex Tank and Terminals and Jacobs Engineering Group, Inc. The Strategic Petroleum Reserve stores an emergency supply of crude oil stored at four sites in huge underground salt caverns along the Texas and Louisiana Gulf Coast.

Los Alamos National Laboratory. Since 2006, as one of the owners of Los Alamos National Security, LLC, we have been involved in the management and operations of this facility. Previously, we acted as a subcontractor to the University of California at this facility, providing nuclear facility operations assessment, advisory and technical support services. 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.

Oak Ridge National Laboratory. This facility is managed and operated by UT-Battelle, LLC for the DOE. As an integrated subcontractor to UT-Battelle, LLC, we provide technical support in the areas of nuclear facility management and operation. The Oak Ridge National Laboratory is a multi-disciplined science and technology complex located on a 58-square mile site near Oak Ridge, Tennessee.

Lawrence Livermore National Laboratory. Lawrence Livermore National Security, LLC is a consortium comprised of the University of California, Bechtel National, URS Corporation and us, which was awarded a contract in late 2007 to manage the facility in Livermore, California. The laboratory serves as a national resource in science and engineering, focused on national security, energy, the environment and bioscience, with special responsibility for nuclear weapons.

·	Clinch River. Babcock & Wilcox Technical Services Clinch River, LLC was awarded a contract from USEC, Inc. in 2007 to manufacture classified metal parts for the American Centrifuge Program. The initial phase includes equipment procurement and preparation of the facility for manufacturing.

Savannah River Site. As an integrated contractor at this site, we are responsible for nuclear materials management and the startup and operation of a facility to extract tritium, a radioactive form of hydrogen used in the United States’ nuclear weapons program. In January 2008, the management and operations contract for the site was awarded to a new team, which does not include us. We are currently bidding on a second contract at this site and expect the award to be announced in early 2008. 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.

Rocky Flats Environmental Technology Site. Through Safe Sites of Colorado, L.L.C, an entity we co-own with Westinghouse Government Environmental Services Company L.L.C., we provide professional engineering and management services in support of the closure project at the Rocky Flats Environmental Technology Site. The closure project involves decommissioning and decontamination activities to stabilize plutonium and ship the waste to a storage facility. The activities at this site are basically complete.

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With manufacturing facilities located in Barberton, Ohio, Euclid, Ohio, Mount Vernon, Indiana, and Lynchburg, Virginia, we specialize in the design and manufacture of close-tolerance and high-quality equipment for nuclear applications. In addition, we are a leading manufacturer of critical nuclear components, fuels and assemblies for government and commercial uses. We have supplied nuclear components for DOE programs since the 1950s. In addition, we are the largest domestic supplier of research reactor fuel elements for colleges, universities and national laboratories. We also provide 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. We also have over 100 years of experience in supplying heavy fabrications for industrial use, including components for defense applications.

We work closely with the DOE supported non-proliferation program. Currently, this program is assisting in the development of a high-density, low-enriched uranium fuel required for high-enriched uranium test reactor conversions. In addition, we have 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 our Lynchburg, Virginia site.

We have an experienced staff of design and manufacturing engineers capable of performing full scope, prototype design work coupled with manufacturing integration. Our engineering capabilities include:

·	steam separation equipment design and development;

·	thermal-hydraulic design of reactor plant components;

·	structural component design for precision manufacturing;

·	materials expertise in high-strength, low-alloy steels, nickel-based materials and others;

·	material procurement of tubing, forgings, weld wire; and

·	fully-equipped metallographic and chemical analysis laboratory facility.

We also implement strong quality assurance programs for our Government Operations’ products.

Customers

The U.S. Government is the primary customer of our Government Operations segment, comprising 97% of segment revenues for the years ended December 31, 2007 and 2006.

The U.S. Government accounted for approximately 12%, 15%, and 31% of our total consolidated revenues for the years ended December 31, 2007, 2006, and 2005, respectively, substantially all of which relates to nuclear components.

Contracts

Our contracts with the federal government are subject to annual funding determinations. In addition, contracts between 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 required. 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.

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Backlog

As of December 31, 2007 and 2006, our Government Operations segment’s backlog amounted to approximately $1.8 billion and $1.3 billion, or approximately 18% and 17%, respectively, of our total consolidated backlog. Of our December 31, 2007 backlog in this segment, we expect to recognize revenues as follows (in approximate millions):

	Amount
Quarter Ending:
March 31, 2008	$	150
June 30, 2008	$	160
September 30, 2008	$	160
December 31, 2008	$	160

Year Ending December 31, 2009	$	520

Thereafter	$	640

As of December 31, 2007, this segment’s backlog with the U.S. Government was $1.8 billion (of which $13.7 million had not yet been funded), or approximately 18% of our total consolidated backlog. We do not include the value of our management and operating contracts in backlog.

During the year ended December 31, 2007, the U.S. Government awarded new orders of approximately $1.0 billion to this segment. The amount of new orders awarded during the year ended December 31, 2007 does not include the acquired U.S. Government backlog of Marine Mechanical Corporation of $149.8 million recorded on the date of acquisition.

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. This 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., URS Corporation, CH2M Hill, Inc., Fluor Corporation, Lockheed Martin Corporation, Jacobs Engineering Group, Inc., EnergySolutions, Inc. 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.

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See Section 1A, “Risk Factors,” for further information on factors affecting demand.

D. POWER GENERATION SYSTEMS

General

Our Power Generation Systems segment 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. We also have strategic licensing arrangements for our technology and products.

Properties

The administrative offices for our Power Generation Systems segment are located in Barberton, Ohio and Lynchburg, VA. This segment’s principal manufacturing facilities are located in:

·	West Point, Mississippi;

·	Lancaster, Ohio;

·	Cambridge, Ontario, Canada;

·	Esbjerg, Denmark;

·	Melville, Saskatchewan, Canada; and

·	Jingshan, Hubei, China.

We own each of these facilities.

The 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. (“Diamond Power”), one of our wholly owned subsidiaries. Diamond Power 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.

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.

The 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 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 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.

In addition to the above, our Power Generation Systems segment has several smaller facilities in different locations around the world and has a significant boiler manufacturing joint venture in China. This joint venture was established in 1986 and operates an 111,000 square meter facility, which is ISO 9001 certified and produces industrial and utility

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boilers. It operates the largest heavy drum shop in northern China. This shop is equipped to handle welding activities, lifting heat treatment and transportation, and it employs over 2,000 people.

Operations

Through our Power Generation Systems segment, we:

·	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;

·	manufacture heavy-pressure equipment for energy conversion, such as boilers fueled by coal, oil, bitumen, natural gas, solid municipal waste, biomass and other fuels;

·	fabricate steam generators and reactor heads for nuclear power plants;

·	design and supply environmental control systems, including both wet and dry scrubbers for flue gas desulfurization, modules for selective catalytic reduction of the oxides of nitrogen, equipment to capture particulate matter, such as baghouses and electrostatic precipitators, and similar devices;

·	construct power plant equipment and provide related heavy mechanical erection services;

·	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;

·	provide inventory services to help customers respond quickly to plant interruptions and construction crews to assist in maintaining and repairing operating equipment; and

·	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.

We also have investments in several unconsolidated entities. We account for these entities under the equity method of accounting. Descriptions of these entities are as follows:

Ebensburg Power Company & Ebensburg Investors Limited Partnership. These entities were formed by subsidiaries within our Power Generation Systems segment and ESI Energy, Inc. for the purpose of arranging for engineering, constructing, owning and operating a combined solid waste and cogeneration facility located in Cambria County near Ebensburg, Pennsylvania. This facility uses bituminous waste coal for its primary fuel and sells generated electricity to a utility and steam to a hospital. Our Power Generation Systems segment has a long history of selling its goods and services to power producers, particularly those using fossil fuel-fired steam generating systems. These entities were formed to hold our interest in a utility, which, at the time, was part of the strategic plan for our power systems generation business.

Halley & Mellowes Pty. Ltd. Diamond Power owns an interest in this Australian company. Halley & Mellowes Pty. Ltd. is complementary to Diamond Power and has helped Diamond Power to become the largest supplier of boiler-cleaning equipment in the world. Halley & Mellowes Pty. Ltd. sells soot blowers, boiler cleaning equipment, valves and material handling equipment all of which are complimentary to Diamond Power’s product lines. In addition, Halley & Mellowes Pty. Ltd. shares the same customer base as Diamond Power and is basically an extension of Diamond Power’s operations.

Babcock & Wilcox Beijing Company, Ltd. We own equal interests in this entity with Beijing Jingcheng Machinery Electric Holding Company, Ltd. Babcock & Wilcox Beijing Company, Ltd. is located in Beijing, China, and its main activities are the design, manufacturing, production and sale of various power plant and industrial boilers. We formed this entity to expand our markets internationally and to provide additional capacity to our Power Generation Systems segment’s existing boiler business.

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Our Power Generation Systems segment’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 years ended December 31, 2007 and 2006 were as follows (dollars in thousands):

	Revenues					Segment Income
	Amount		Percent			Amount		Percent

Year ended December 31, 2007	$	411,459		7	%	$	49,122		6	%
Year ended December 31, 2006	$	415,995		10	%	$	32,050		8	%

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 our Power Generation Systems segment after an extensive evaluation process based on competitive bids.

Our Power Generation Systems segment’s five largest customers, as a percentage of our total consolidated revenues, during the years ended December 31, 2007 and 2006 were as follows:

Year Ended December 31, 2007:
American Electric Power Company, Inc.	5.1	%
TXU Corp.	4.1	%
Allegheny Energy Incorporated	2.6	%
First Energy Corporation	2.2	%
Bruce Power Limited	1.9	%

Year Ended December 31, 2006:
American Electric Power Company, Inc.	5.3	%
Duke Energy Corporation	4.0	%
Bechtel Power Group Incorporated	2.7	%
Bruce Power Limited	2.6	%
First Energy Corporation	1.5	%

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 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.

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, bid and performance bonds or other guarantees to secure bids or performance under contracts. While these letters of credit, bonds and other guarantees may involve significant dollar amounts, historically, there have been no material payments to our customers under these arrangements.

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Backlog

As of December 31, 2007 and 2006, our Power Generation Systems segment’s backlog amounted to approximately $3.3 billion and $2.2 billion, respectively. This represents approximately 33% and 29% of our total consolidated backlog at December 31, 2007 and 2006, respectively. Of the December 31, 2007 backlog in our Power Generation Systems segment, we expect to recognize revenues as follows (in approximate millions):

	Amount
Quarter Ending:
March 31, 2008	$	550
June 30, 2008	$	440
September 30, 2008	$	350
December 31, 2008	$	280

Year Ended December 31, 2009	$	610

Thereafter	$	1,050

In addition to our expected revenue recognition from ending backlog at December 31, 2007, our Power Generation Systems segment also realizes revenues from orders received and completed in the same fiscal quarter, including significant revenues from our parts and services business.

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

Our Power Generation Systems segment primarily competes with:

·	a number of domestic and foreign-based companies specializing in steam-generating systems, equipment and services, including Alstom S.A., Doosan Babcock, Babcock Power, Inc., Foster Wheeler Ltd., Mitsubishi Heavy Industries and Hitachi, Ltd.;

·	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

·	other suppliers of replacement parts, repair and alteration services and other services required to retrofit and maintain existing steam systems.

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Factors Affecting Demand

·	prices for electricity, along with the cost of production and distribution;

·	prices for coal and natural gas and other sources used to produce electricity;

·	demand for electricity, paper and other end products of steam-generating facilities;

·	availability of other sources of electricity, paper or other end products;

·	requirements for environmental improvements;

·	impact of potential regional, state, national and/or global requirements to significantly limit or reduce greenhouse gas emissions in the future;

·	level of capacity utilization at operating power plants, paper mills and other steam-using facilities;

·	requirements for maintenance and upkeep at operating power plants and paper mills to combat the accumulated effects of wear and tear;

·	ability of electric generating companies and other steam users to raise capital; and

·	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 $52.0 million, $45.2 million and $34.1 million in the years ended December 31, 2007, 2006 and 2005, 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 $16.5 million, $26.5 million and $30.8 million in the years ended December 31, 2007, 2006 and 2005, 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, but may not be limited to, war and confiscation of property in some areas of the world, pollution liability, owned aircraft liability, business interruption, liabilities related to occupational health exposures (including asbestos) and liability related to risk of loss of our work in progress and customer-owned materials in our care, custody and control. 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.

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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 is set to expire on December 31, 2025. Our Government Operations segment 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 some coverage under commercially available nuclear liability and property insurance for two locations that are currently licensed to possess special nuclear materials. These two locations are located at our Lynchburg, Virginia site. These facilities are insured under a nuclear liability policy that also insures the facility of AREVA Enterprises, Inc. (“AREVA”), which we sold during the fiscal year ended March 31, 1993. The AREVA facility and our facility share the same nuclear liability insurance limit, as the commercial insurer would not allow AREVA to obtain a separate nuclear liability insurance policy. Due to the type of contracts with the U.S. Government, our facilities in Lynchburg have statutory indemnity and limitation of liability under the Price-Anderson Act for public liability claims related to nuclear incidents. However, we have some risk of loss for nuclear material and are not able to buy insurance to insure against this potential liability.

Through two limited liability companies, our Government Operations segment 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.

In our Power Generation Systems segment, principally through its manufacture of heavy-pressure equipment for energy conversion, such as boilers, and its fabrication of nuclear steam generators, we are 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. There is also potential liability resulting from multi-jurisdictional disputes or liability in jurisdictions that do not have adequate protections for the manufacturers or suppliers to the nuclear power industry. See Note 11 to our consolidated financial statements included in this report for additional information.

Our Offshore Oil and Gas Construction segment is subject to the many 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. We have additional exposure because this segment uses expensive construction equipment, sometimes under extreme weather conditions, often in remote areas of the world. In many cases, this segment 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

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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 11 to our consolidated financial statements included in this report for additional information on these issues.

We have several wholly owned insurance subsidiaries that customarily provide workers compensation, employer’s liability, commercial general liability, maritime employer’s liability and automotive liability insurance to support our global operations. These captives have, from time to time, in the past provided builder’s risk and marine hull 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 risks may be considerable in any given year or cumulatively. 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.

Additionally, upon the February 22, 2006 effectiveness of the settlement relating to the Chapter 11 Bankruptcy, we and most of our subsidiaries contributed substantial insurance rights to the asbestos personal injury trust, including rights to (1) certain pre-1979 primary and excess insurance coverages and (2) certain of our 1979-1986 excess insurance coverage, 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, we may have underinsured or uninsured exposure for non-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, 2007, we employed approximately 28,400 persons, compared with 27,800 at December 31, 2006. Approximately 8,300 of our employees were members of labor unions at December 31, 2007, compared with approximately 11,100 at December 31, 2006. 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:

·	construction and equipping of offshore production platforms and other offshore facilities;

·	construction and equipping of electric power and other industrial facilities;

·	possessing and processing special nuclear materials;

·	marine vessel safety;

·	workplace health and safety;

·	currency conversions and repatriation;

·	taxation of foreign earnings and earnings of expatriate personnel; and

·	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.

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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 $9.5 million in the year ended December 31, 2007. In addition, compliance with existing environmental regulations necessitated capital expenditures of $4.9 million in the year ended December 31, 2007. We expect to spend another $6.9 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.

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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, one of our subsidiaries decided to close its nuclear manufacturing facilities in Parks Township, Armstrong County, Pennsylvania (the "Parks Facilities") and proceeded to decommission the facilities in accordance with its then-existing license from the Nuclear Regulatory Commission (the “NRC”). The facilities were subsequently transferred to another subsidiary of ours in the fiscal year ended March 31, 1998, and, during the fiscal year ended March 31, 1999, that subsidiary 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. An application to terminate the NRC license for the Parks Township facility was filed, 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 11 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 our Government Operations segment 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. We will continue to provide financial assurance aggregating $24.5 million during the year ending December 31, 2008 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 our 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, 2007 and 2006, we had total environmental reserves, including provisions for the facilities discussed above, of $18.8 million and $18.6 million, respectively. Of our total environmental reserves at December 31, 2007 and 2006, $7.0 million and $9.7 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.

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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:

·	general economic and business conditions and industry trends;

·	general developments in the industries in which we are involved;

·	decisions about offshore developments to be made by oil and gas companies;

·	decisions on spending by the U.S. Government and electric power generating companies;

·	the highly competitive nature of most of our businesses;

·	the ability of our suppliers to deliver raw materials in sufficient quantities and in a timely manner;

·	our future financial performance, including compliance with covenants in our credit agreements and other debt instruments and availability, terms and deployment of capital;

·	the continued availability of qualified personnel;

·	the operating risks normally incident to our lines of business;

·	changes in, or our failure or inability to comply with, government regulations and adverse outcomes from legal and regulatory proceedings;

·	impact of potential regional, national and/or global requirements to significantly limit or reduce greenhouse gas emissions in the future;

·	changes in, and liabilities relating to, existing or future environmental regulatory matters;

·	rapid technological changes;

·	the realization of deferred tax assets, including through a reorganization we completed in December 2006;

·	the consequences of significant changes in interest rates and currency exchange rates;

·	difficulties we may encounter in obtaining regulatory or other necessary approvals of any strategic transactions;

·	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;

·	the possibilities of war, other armed conflicts or terrorist attacks;

·	the effects of asserted and unasserted claims;

·	our ability to obtain surety bonds and letters of credit;

·	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;

·	the aggregated risks retained in our insurance captives; and

·	the impact of the loss of insurance rights as part of the Chapter 11 Bankruptcy 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

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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 the Investor Relations section of 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”). You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with 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. 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:

·	prevailing oil and gas prices;

·	expectations about future prices;

·	the cost of exploring for, producing and delivering oil and gas;

·	the sale and expiration dates of available offshore leases;

·	the discovery rate of new oil and gas reserves in offshore areas;

·	domestic and international political, military, regulatory and economic conditions;

·	technological advances; and

·	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:

·	prices for electricity, along with the cost of production and distribution;

·	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;

·	availability of other sources of electricity, paper or other end products;

·	requirements for environmental improvements, including potential carbon dioxide (“CO2”) legislation;

·	level of capacity utilization at operating power plants, paper mills and other steam-using facilities;

·	requirements for maintenance and upkeep at operating power plants and paper mills to combat the accumulated effects of wear and tear;

·	ability of electric generating companies and other steam users to raise capital; and

·	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, therefore, 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.

Our backlog is subject to unexpected adjustments and cancellations and is, therefore, an uncertain indicator of our future earnings.

There can be no assurance that the revenues projected in our backlog will be realized or, if realized, will result in profits. Because of changes in project scope and schedule, we cannot predict with certainty when or if backlog will be performed. In addition, even where a project proceeds as scheduled, it is possible that contracted parties may

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default and fail to pay amounts owed to us. Material delays, cancellations or payment defaults could materially affect our financial condition, results of operations and cash flows.

Reductions in our backlog due to cancellation or modification by a customer or for other reasons may adversely affect, potentially to a material extent, the revenues and earnings we actually receive from contracts included in our backlog. Many of the contracts in our backlog provide for cancellation fees in the event customers cancel projects. These cancellation fees usually provide for reimbursement of our out-of-pocket costs, revenues for work performed prior to cancellation and a varying percentage of the profits we would have realized had the contract been completed. However, we typically have no contractual right upon cancellation to the total revenues reflected in our backlog. Projects may remain in our backlog for extended periods of time. If we experience significant project terminations, suspensions or scope adjustments to contracts reflected in our backlog, our financial condition, results of operations, and cash flows may be adversely impacted.

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.

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:

·	risks of war, terrorism and civil unrest;

·	expropriation, confiscation or nationalization of our assets;

·	renegotiation or nullification of our existing contracts;

·	changing political conditions and changing laws and policies affecting trade and investment;

·	overlap of different tax structures;

·	risk of changes in foreign currency exchange rates; and

·	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:

·	accidents resulting in injury to or the loss of life or property;

·	environmental or toxic tort claims, including delayed manifestation claims for personal injury or loss of life;

·	pollution or other environmental mishaps;

·	hurricanes, tropical storms and other adverse weather conditions;

·	mechanical failures;

·	collisions;

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·	property losses;

·	business interruption due to political action in foreign countries or other reasons; and

·	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. We rely heavily on certain items of equipment, including vessels and heavy manufacturing equipment and our fabrication locations, to execute the work we are hired to perform. If these items became unavailable to us for any reason, including for loss or damage, political or terrorist event or otherwise, we may not be able to timely meet the requirements of our customer contracts and may be in default of our contractual obligations for one or more customers, subjecting us to delay damage claims, including for loss of profits. 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 relating to the Chapter 11 Bankruptcy, we and most of our subsidiaries contributed substantial insurance rights to the asbestos personal injury trust, including rights to (1) certain pre-1979 primary and excess insurance coverages and (2) certain of our 1979-1986 excess insurance coverage, 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, we may have underinsured or uninsured exposure for asbestos claims or other personal injury or other claims against subsidiaries not debtors in the Chapter 11 Bankruptcy, for which we would have had insurance rights under these coverages if the insurance rights had not been contributed to the asbestos personal injury trust.

Through two of limited liability companies, our Government Operations segment 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.

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 in a given year. 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, utilities and major oil and gas companies. In particular, our Government Operations segment derives substantially all its revenue from the U.S. Government. Some

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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 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.

Our business strategy includes acquisitions to continue our growth. Acquisitions of other businesses can create certain risks and uncertainties.

We may pursue growth through the acquisition of businesses or assets that will enable us to strengthen or broaden the types of projects we execute and also expand into new markets. We may be unable to implement this growth strategy if we cannot identify suitable businesses or assets, reach agreement on potential strategic acquisitions on acceptable terms or for other reasons. Moreover, an acquisition involves certain risks, including:

·	difficulties relating to the assimilation of personnel, services and systems of an acquired business and the assimilation of marketing and other operational capabilities;

·	challenges resulting from unanticipated changes in customer relationships subsequent to acquisition;

·	additional financial and accounting challenges and complexities in areas such as tax planning, treasury management, financial reporting and internal controls;

·	assumption of liabilities of an acquired business, including liabilities that were unknown at the time the acquisition transaction was negotiated;

·	diversion of management’s attention from day-to-day operations;

·	failure to realize anticipated benefits, such as cost savings and revenue enhancements;

·	potentially substantial transaction costs associated with business combinations; and

·	potential impairment resulting from the overpayment for an acquisition.

Future acquisitions may require us to issue additional equity or obtain debt financing, which may not be available on attractive terms. Moreover, to the extent an acquisition transaction financed by non-equity consideration results in goodwill, it will reduce our tangible net worth, which might have an adverse effect on potential credit and bonding capacity.

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Additionally, an acquisition may bring us into businesses we have not previously conducted and expose us to additional business risks that are different than those we have traditionally experienced.

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:

·	construction and equipping of production platforms and other offshore facilities;

·	marine vessel safety;

·	currency conversions and repatriation;

·	oil exploration and development;

·	clean air and other environmental protection legislation;

·	taxation of foreign earnings and earnings of expatriate personnel; and

·	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 11 to our consolidated financial statements included in this report.

U.S. coal-fired power plants have been scrutinized by environmental groups and government regulators over the emissions of potentially harmful pollutants. In addition to recent legislation at the state level, the U.S. Congress is considering legislation that would limit greenhouse gas emissions, including CO2. In April 2007, the U.S. Supreme Court ruled that the U.S. Environmental Protection Agency has some authority to regulate greenhouse gases under

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the Clean Air Act. Some plans for coal-fired power plants have recently been cancelled or suspended in several states, although more new coal-fired power plants are being planned to meet the predicted increase in electricity demand. Also, in February 2008, three of the nation’s largest investment banks announced new environmental standards to ensure lenders evaluate risks associated with investments in coal-fired power plants. Such standards could make it potentially more difficult for new U.S. coal-fired power plants to secure financing.

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 11 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. UNRESOLVED STAFF COMMENTS

None

Item 2. PROPERTIES

For a description of our significant properties, see Item 1, Section B., “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. LEGAL PROCEEDINGS

The information set forth under the heading “Investigations and Litigation” in Note 11, “Contingencies and Commitments,” to our consolidated financial statements included in this report is incorporated by reference into this Item 3.

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, 2007.

P A R T I I

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 2007. 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 as exhibits to this report.

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High and low stock prices by quarter in the years ended December 31, 2007 and 2006, as adjusted for the two-for-one stock split effected in September 2007 and the three-for-two stock split effected in May 2006, were as follows:

YEAR ENDED DECEMBER 31, 2007
	SALES PRICE
QUARTER ENDED	HIGH		LOW
March 31, 2007	$	27.99	$	22.16
June 30, 2007	$	42.41	$	23.96
September 30, 2007	$	55.30	$	34.32
December 31, 2007	$	62.78	$	45.69

YEAR ENDED DECEMBER 31, 2006
	SALES PRICE
QUARTER ENDED	HIGH		LOW
March 31, 2006	$	18.77	$	14.87
June 30, 2006	$	24.67	$	18.00
September 30, 2006	$	25.68	$	19.22
December 31, 2006	$	26.68	$	18.85

We have not paid cash dividends on MII’s common stock since the second quarter of 2000 and do not currently have 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 January 31, 2008, there were approximately 3,025 record holders of our common stock.

The following table provides information on our equity compensation plans as of December 31, 2007:

Equity Compensation Plan Information

Plan Category	Number of securities to be issued upon exercise of outstanding options and rights		Weighted-average exercise price of outstanding options and rights		Number of securities remaining available for future issuance
Equity compensation plans approved by security holders		2,381,449	$	5.49		7,397,650

Equity compensation plans not approved by security holders (1)		747,243	$	3.38		-

Total		3,128,692	$	4.98		7,397,650
(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.

The following graph provides a comparison of our five-year, cumulative total shareholder return from December 2002 through December 2007 to the return of S&P 500, our current peer group and our peer group in effect at December 31, 2006. The 2006 Custom Peer Group was used in the presentation of the performance graph we included in our Annual Report on Form 10-K for the year ended December 31, 2006. The 2007 Custom Peer Group is a new group of companies we selected in order to provide a better representation of engineering and construction companies similarly situated to us.

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The peer groups used for the five-year comparison were comprised of the following companies:

2007 Custom Peer Group

·	Cal Dive International, Inc.

·	Chicago Bridge & Iron Company N.V.

·	Fluor Corporation

·	Foster Wheeler, Ltd.

·	Jacobs Engineering Group, Inc.

KBR, Inc.

·	Oceaneering International, Inc.

·	The Shaw Group, Inc.

·	URS Corporation

2006 Custom Peer Group

·	Acergy S.A.

·	Alliant Techsystems, Inc.

·	Fluor Corporation

·	Global Industries, Ltd.

·	GlobalSantaFe Corporation

·	Goodrich Corporation

·	Halliburton Company

·	Jacobs Engineering Group, Inc.

·	Rockwell Collins, Inc.

·	The Shaw Group, Inc.

Technip

·	Washington Group International, Inc.

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Item 6. SELECTED FINANCIAL DATA

	For the Years Ended
	2007		2006(2)		2005(3)		2004(3)		2003 (3)
	(In thousands, except for per share amounts)
Revenues	$	5,631,610	$	4,120,141	$	1,839,740	$	1,912,910	$	2,329,486

Income (Loss) from Continuing Operations before Cumulative Effect of Accounting Change (1)	$	607,828	$	317,621	$	205,583	$	63,123	$	(84,082	)
Income (Loss) before Cumulative Effect of Accounting Change	$	607,828	$	330,515	$	205,687	$	59,919	$	(94,597	)
Net Income (Loss)	$	607,828	$	330,515	$	205,687	$	59,919	$	(90,887	)

Basic Earnings (Loss) per Common Share(4):
Income (Loss) from Continuing Operations before Cumulative Effect of Accounting Change	$	2.72	$	1.46	$	1.00	$	0.32	$	(0.44	)
Income (Loss) before Cumulative Effect of Accounting Change	$	2.72	$	1.52	$	1.00	$	0.30	$	(0.49	)
Net Income (Loss)	$	2.72	$	1.52	$	1.00	$	0.30	$	(0.47	)

Diluted Earnings (Loss) per Common Share(4):
Income (Loss) from Continuing Operations before Cumulative Effect of Accounting Change	$	2.66	$	1.39	$	0.94	$	0.31	$	(0.44	)
Income (Loss) before Cumulative Effect of Accounting Change	$	2.66	$	1.45	$	0.94	$	0.29	$	(0.49	)
Net Income (Loss)	$	2.66	$	1.45	$	0.94	$	0.29	$	(0.47	)

Total Assets	$	4,411,486	$	3,633,762	$	1,709,962	$	1,419,788	$	1,271,091
Current Maturities of Long-Term Debt	$	6,599	$	257,492	$	4,250	$	12,009	$	37,217
Long-Term Debt	$	10,609	$	15,242	$	207,861	$	268,011	$	279,682

(1) Cumulative effect of accounting change is due to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” during the year ended December 31, 2003.

(2) Results for the year ended December 31, 2006 include approximately ten months for the principal operating subsidiaries of our Power Generation Systems segment, which were reconsolidated into our results effective February 22, 2006. We did not consolidate the results of operations of these entities in our consolidated financial statements from February 22, 2000 through February 22, 2006 due to the Chapter 11 Bankruptcy. See Note 21 to our consolidated financial statements included in this report for information on the Chapter 11 Bankruptcy. Additionally, the results for the year ended December 31, 2006 have been restated to reflect the impact of the change in accounting for drydocking costs, as discussed in Note 1 to our consolidated financial statements included in this report.

(3) Financial data for the years ended December 31, 2005, 2004 and 2003 have been restated to reflect the impact of discontinued operations, as discussed in Note 3 to our consolidated financial statements included in this report, and to reflect the impact of the change in accounting for drydocking costs, as discussed in Note 1 to our consolidated financial statements included in this report.. Also, we did not consolidate the results of operations of the principal operating subsidiaries of our Power Generation Systems segment in our consolidated financial statements from February 22, 2000 through February 22, 2006 due to the Chapter 11 Bankruptcy. See Note 21 to our consolidated financial statements included in this report for information on the Chapter 11 Bankruptcy.

(4) Per share amounts for the years ended December 31, 2006, 2005, 2004 and 2003 have been restated to reflect the stock splits effected during the years ended December 31, 2007 and 2006, as discussed in Note 9 to our consolidated financial statements included in this report.

Results for the year ended December 31, 2005 include the reversal of a federal deferred tax valuation allowance adjustment totaling approximately $50.4 million.

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.

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Results for the year ended December 31, 2003 include losses on three spar contracts in our Offshore Oil and Gas Construction segment, the Carina Aries project and the Belanak FPSO project totaling approximately $120 million.

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 of 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, equity or some combination thereof. It is our policy to not comment on any potential acquisition/transaction until a definitive agreement has been reached.

Offshore Oil and Gas Construction Segment – Recent Operating Results and Outlook

Our Offshore Oil and Gas Construction segment produced strong financial results in 2007. We expect the backlog of approximately $4.8 billion at December 31, 2007 to produce revenues for 2008 of approximately $3.0 billion, not including any change orders or new contracts that may be awarded during the year. Our Offshore Oil and Gas Construction segment is actively bidding on and, in some cases, beginning preliminary work on projects that we expect will be awarded to it in 2008, subject to successful contract negotiations, which are not currently in backlog.

The demand for our Offshore Oil and Gas Construction segment’s products and services is dependent primarily on the capital expenditures of the world’s major oil and gas producing companies and foreign governments for construction of development projects in the regions in which we operate. In recent years, the worldwide demand for energy, along with high prices for oil and gas, has led to strong levels of capital expenditures by the major oil and gas companies and foreign governments. This activity contributed to the strong financial results our Offshore Oil and Gas Construction segment has produced in the recent years. We believe these trends will continue in 2008 and will be a major contributor to our expected 2008 results.

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

Our Government Operations Segment produced strong financial results in 2007. We expect the backlog of approximately $1.8 billion at December 31, 2007 to produce revenues for 2008 of approximately $630 million, not including any change orders or new contracts that may be awarded during the year.

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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, this segment is a significant participant in the defense industry. With its unique capability of full life-cycle management of special nuclear materials, facilities and technologies, our Government Operations segment is well positioned to continue to participate in the continuing cleanup, operation and management of the nuclear sites and weapons complexes maintained by the U.S. Department of Energy (the “DOE”).

Power Generation Systems Segment – Recent Operating Results and Outlook

Our Power Generation Systems segment produced strong financial results in 2007. We expect the backlog of approximately $3.3 billion at December 31, 2007 to produce revenues for 2008 of approximately $1.6 billion, not including any change orders or new contracts that may be awarded during the year. Our Power Generation Systems segment is actively bidding on and, in some cases, beginning preliminary work on projects that we expect will be awarded to it in 2008, subject to successful contract negotiations, which are not currently in backlog.

In June 2006, our Power Generation Systems segment 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. Subsequently, we received notice from TXU to suspend activity on five of the eight boilers and SCR systems. We did not include the value of these eight units in our backlog at December 31, 2006 due to their uncertainty.

The five suspended contracts were formally cancelled by execution of a termination and settlement agreement dated April 13, 2007. During the year ended December 31, 2007, we received cash payments totaling $124 million from TXU, which completed the $243 million termination settlement obligation from TXU. Of the total $243 million settlement, we recognized $178 million as revenue during the year ended December 31, 2007 and $65 million as revenue during the year ended December 31, 2006.

TXU’s payments totaling $243 million completed the obligations between our Power Generation Systems segment and TXU for the cancelled units; therefore, we do not expect the termination of the five cancelled contracts to have a material impact on our results of operations or cash flows in future periods, including related amounts accrued for costs incurred and owed to various subcontractors and vendors. Backlog in our Power Generation Systems segment at December 31, 2007 is higher compared to June 30, 2006, which was the period in which we originally recorded all eight TXU contracts in our backlog. Our liquidity position for this segment remains strong, and we expect it to remain so throughout 2008 and 2009.

Our Power Generation Systems segment continues to fulfill its contracts to supply the three units not covered by the termination and settlement agreement with TXU. The value of these units in our backlog totaled approximately $315 million at December 31, 2007, and we will continue to recognize revenue and costs on these contracts under percentage-of-completion accounting. We expect that our execution of these remaining contracts will produce positive operating margins, comparable to other projects of a similar nature in this segment, as they are completed over the next 12 to 48 months.

Our Power Generation Systems segment’s overall activity depends mainly on the capital expenditures of electric power generating companies and other steam-using industries. This 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.

U.S. coal-fired power plants have been scrutinized by environmental groups and government regulators over the emissions of potentially harmful pollutants. In addition, the U.S. Congress is considering legislation that would limit greenhouse gas emissions, including CO2. In April 2007, the U.S. Supreme Court ruled that the U.S. Environmental Protection Agency has some authority to regulate greenhouse gases under the Clean Air Act. Some plans for coal-fired power plants have recently been cancelled or suspended in several states, although more new coal-fired power plants are being planned to meet the predicted increase in electricity demand. Also, in February 2008, three of the nation’s largest investment banks announced new environmental standards to ensure lenders evaluate risks associated with investments in coal-fired power plants. Such standards could make it potentially more difficult for new U.S. coal-fired power plants to secure financing.

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According to the International Energy Agency, consumption of electricity worldwide is expected nearly to double in the next quarter century. While we cannot predict what impact potential future legislation and regulations concerning CO2 and other emissions will have on our results of operations, it is possible such legislation could favorably impact the environmental retrofit and service businesses of our Power Generation Systems segment.

Other

At December 31, 2007, in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” and SFAS No. 87, “Employers’ Accounting for Pensions,” the underfunded status of our defined benefit plans improved by approximately $146.0 million from 2006. This improvement was primarily due to increasing our discount rate in 2007 to 6.25% from 6.0% for three of our major qualified plans, additional contributions of $132.2 million in 2007 and return on plan assets.

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.

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”), issued by the American Institute of Certified Public Accountants. 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.

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 during the years ended December 31, 2007 and 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.

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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.

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. We recognize drydocking costs for our marine fleet as a prepaid asset when incurred and amortize the expense over the period of time between drydockings, generally three to five years. We adopted this accounting policy for our drydocking costs, commonly referred to as 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 cannot 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’

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Accounting for Defined Benefit Pension and Other Postretirement Plans,” 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 7 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 11 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,” 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, 2007 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. Effective January 1, 2007, we adopted the provision of Financial Accounting Standards Board (the “FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), as more fully discussed in Notes 1 and 5 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.

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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, 2007 COMPARED TO YEAR ENDED DECEMBER 31, 2006

McDermott International, Inc. (Consolidated)

Consolidated revenues increased approximately 37%, or $1.5 billion, to $5.6 billion for year ended December 31, 2007, compared to $4.1 billion for the year ended December 31, 2006. Our Offshore Oil and Gas Construction segment generated a 52% increase in its revenues in the year ended December 31, 2007 compared to the year ended December 31, 2006, primarily attributable to its Middle East and Asia Pacific regions. In addition, our Power Generation Systems segment revenues increased approximately 33% in the year ended December 31, 2007, as compared to the year ended December 31, 2006, primarily attributable to 2006 including approximately ten months of revenues from B&W PGG and its subsidiaries, compared to 12 months for 2007, and the recognition of revenues of approximately $178 million during 2007 from our termination and settlement agreement executed with TXU on the cancellation of five contracts to supply TXU supercritical, coal-fired boilers and SCR’s, as described above. Our Government Operations segment revenues increased approximately 10% in the year ended December 31, 2007, as compared to the year ended December 31, 2006.

Consolidated segment operating income, which, for purposes of this discussion and the segment discussions that follow, is before equity in income (losses) of investees and gains (losses) on asset disposals and impairments – net, increased $308.5 million from $398.8 million in the year ended December 31, 2006 to $707.3 million in the year ended December 31, 2007. The segment operating income of each of our Offshore Oil and Gas Construction and Power Generation Systems segments improved substantially in the year ended December 31, 2007, as compared to the year ended December 31, 2006. Our Government Operations segment operating income increased slightly in the year ended December 31, 2007, as compared to the year ended December 31, 2006.

Offshore Oil and Gas Construction

Revenues increased approximately 52%, or $835.4 million, to $2.4 billion for the year ended December 31, 2007, compared to $1.6 billion for the year ended December 31, 2006, primarily due to increased activities in our Middle East ($393.6 million) and Asia Pacific ($226.0 million) regions. Our revenues are principally derived from capital expenditures of major offshore oil and gas construction projects for oil and gas companies and foreign governments in the regions in which we operate and the successful execution of engineering, construction and installation projects. We experienced increases in our fabrication man-hours and our major marine barge days of 37% and 50%, respectively, in the year ended December 31, 2007, as compared to 2006. In addition, we experienced an increase in revenues totaling approximately $34.7 million attributable to the assets we acquired from Secunda International Limited in July 2007.

Segment operating income increased $183.5 million from $214.1 million in the year ended December 31, 2006 to $397.6 million in the year ended December 31, 2007. This increase is primarily attributable to higher fabrication activities, productivity improvements and cost savings in projects in our Middle East and Asia Pacific regions. In addition, our Caspian region improved due to contract change orders and agreements, which were finalized as part of our contract close-out process on projects, and our Americas region improved due to increased fabrication activities. These increases were partially offset by higher general and administrative expenses, including an increase in our stock-based compensation expense attributable to the increase in our stock price, in the year ended December 31, 2007, as compared to the year ended December 31, 2006.

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Gain (loss) on asset disposals and impairments – net increased $23.0 million from a loss of $16.2 million in the year ended December 31, 2006 to a gain of $6.8 million in the year ended December 31, 2007. This change was primarily attributable to a non-cash impairment of $16.4 million in the year ended December 31, 2006 associated with our former joint venture in Mexico. Also contributing to the increase was the recognition during the year ended December 31, 2007 of a deferred gain of approximately $5.4 million related to the sale of our DB17 vessel to this same joint venture in Mexico. We sold the DB17 in September 2004; however, due to this joint venture’s liquidity problems, we deferred recognition of the gain until payment was received on our accounts and notes receivable. Final settlement of the receivables occurred during the year ended December 31, 2007.

Equity in losses of investees increased $1.0 million to $3.9 million in the year ended December 31, 2007, primarily attributable to our share of expenses in a deepwater solutions joint venture.

Government Operations

Revenues increased approximately 10%, or $63.9 million, to $694.0 million in the year ended December 31, 2007, compared to $630.1 million in the year ended December 31, 2006, primarily attributable to higher volumes in the manufacture of nuclear components for certain U.S. Government programs totaling $85.7 million, including additional volume from our acquisition of Marine Mechanical Corporation in Euclid, Ohio.

Segment operating income increased $7.3 million to $90.0 million in the year ended December 31, 2007, compared to $82.7 million in the year ended December 31, 2006, primarily attributable to additional volume from the manufacturing of nuclear components due to contract productivity improvements, along with additional volume from the acquisition of Marine Mechanical Corporation.

Equity in income of investees increased $3.5 million to $31.3 million in the year ended December 31, 2007, primarily due to the termination of our joint venture research and development program and increases in fees at joint ventures in Texas and Tennessee. These increases were partially offset by decreased scope at our joint venture in Idaho.

Power Generation Systems

Revenues increased approximately 33%, or $615.6 million, to $2.5 billion in the year ended December 31, 2007, compared to $1.9 billion in the year ended December 31, 2006. Due to the Chapter 11 Bankruptcy, our results for the year ended December 31, 2006 included approximately ten months of revenues from B&W PGG and its subsidiaries, compared to 12 months for the year ended December 31, 2007. In addition, we recognized revenue totaling $178 million during the year ended December 31, 2007 from our termination and settlement agreement executed with TXU on the cancellation of five contracts to supply TXU supercritical, coal-fired boilers and SCR’s, as described above. Also, in the year ended December 31, 2007, we experienced increases in revenues from our replacement parts business ($36.3 million), our industrial boiler activity ($14.7 million) and our utility steam and system fabrication business ($222.0 million). These increases were partially offset by lower revenues from our replacement nuclear steam generator business ($10.8 million), a reduction in our field service revenues ($4.5 million) and a decrease in revenues from our fabrication, repair and retrofit of existing facilities ($8.8 million).

Segment operating income increased $117.8 million to $219.7 in the year ended December 31, 2007, compared to $101.9 million in the year ended December 31, 2006, primarily attributable to significant benefits recognized in the second and third quarter of 2007 resulting from contract terminations and a variety of settlements. In addition, we experienced increases in segment operating income attributable to higher volumes from our replacement parts business, an increase in margins from our fabrication, repair and retrofit of existing facilities and higher margins on our replacement nuclear steam generator business. We also experienced lower pension plan expense in the year ended December 31, 2007 compared to the year ended December 31, 2006, primarily attributable to the performance of our pension plan assets and a change in our discount rate during the year ended December 31, 2007. These factors were partially offset by higher selling, general and administrative expenses and higher stock-based compensation expense attributable to the increase in our stock price during the year ended December 31, 2007. Also, segment operating income from our construction business decreased during the year ended December 31, 2007 as compared to the year ended December 31, 2006, primarily attributable to losses incurred on several contracts during 2007.

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The year ended December 31, 2006 also included a $27 million provision for warranty, insurance and the settlement of litigation we concluded in early 2007.

Equity in income of investees increased $1.7 million to $14.4 million in the year ended December 31, 2007, primarily attributable to our joint venture in China.

Corporate

Unallocated Corporate expenses increased $11.3 million in the year ended December 31, 2007 from $29.9 million to $41.2 million, primarily attributable to higher departmental expenses and an increase in our stock-based compensation expense due to the improvement in our stock price. These increases were partially offset by lower pension plan expense in the year ended December 31, 2007 compared to the year ended December 31, 2006, primarily attributable to the performance of our pension plan assets and a change in our discount rate during the year ended December 31, 2007.

Other Income Statement Items

Interest income increased by $8.4 million to $62.0 million in the year ended December 31, 2007, primarily due to an increase in average cash equivalents and investments and prevailing interest rates.

Interest expense decreased by $7.8 million to $22.5 million in the year ended December 31, 2007, primarily due to lower average levels of debt outstanding during the year ended December 31, 2007 as compared to the year ended December 31, 2006, partially offset by higher interest and associated amortization and costs on our credit facilities.

We recorded a reduction in interest expense during the year ended December 31, 2006 totaling approximately $13.2 million attributable to a settlement we reached with U.S. and Canadian tax authorities related to transfer pricing issues. Additionally, during the year ended December 31, 2006, we recorded an increase in interest expense totaling approximately $7.5 million for potential U.S. tax deficiencies. These activities resulted in a net U.S. tax-related interest expense adjustment of approximately $5.7 million for the year ended December 31, 2006.

On June 6, 2006, we completed a tender offer and used cash on hand to purchase $200 million in aggregate principal amount of the 11% senior secured notes due 2013 issued by JRMSA (the “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 PGG retired its $250 million promissory note issued in 2005, as part of the Chapter 11 Bankruptcy. As a result of this retirement, we recognized approximately $4.7 million of expense.

Other-net expense decreased by $3.6 million to $10.2 million in the year ended December 31, 2007, primarily due to higher currency exchange losses incurred during the year ended December 31, 2006 and higher bad debt expense during the year ended December 31, 2007.

Provision for Income Taxes

For the year ended December 31, 2007, our provision for income taxes increased $102.4 million to $137.6 million, while income before provision for income taxes increased $392.6 million to $745.5 million. Our effective tax rate was approximately 18% for the year ended December 31, 2007, as compared to 10% for the year ended December 31, 2006. The increase in the effective tax rate was primarily attributable to a tax benefit of $78.1 million recorded during the year ended December 31, 2006, which resulted from the U.S. legal entity reorganization completed on December 31, 2006, as more fully described in the comparative analysis of results for the year ended December 31, 2006 to results for the year ended December 31, 2005.

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Income (loss) before provision for income taxes, provision for (benefit from) income taxes and effective tax rates for our U.S. and non-U.S. jurisdictions are as shown below:

	Income (loss) from Continuing Operations before Provision for Income Taxes				Provision for (Benefit from) Income Taxes					Effective Tax Rate
	2007		2006		2007		2006			2007			2006
	(In thousands)				(In thousands)

United States	$	266,984	$	89,910	$	84,251	$	(8,446	)		31.56	%		(9.39	)%
Non-United States		478,481		262,906		53,386		43,641			11.16	%		16.60	%

Total	$	745,465	$	352,816	$	137,637	$	35,195			18.46	%		9.98	%

We are subject to U.S. federal income tax at a rate of 35% on our U.S. operations plus the applicable state income taxes on our profitable U.S. subsidiaries. Our non-U.S. earnings are subject to tax at various tax rates and different tax regimes, such as a deemed profits tax regime.

Effective January 1, 2007, we adopted the provisions of FIN 48. As a result of this adoption, we recognized a charge of approximately $12.0 million to our accumulated earnings component of stockholders’ equity. As of the adoption date, our unrecognized tax benefits, excluding tax-related interest and penalties, were approximately $70.4 million. As part of the adoption of FIN 48, we began to recognize interest, net of tax, and penalties related to unrecognized tax benefits in income tax expense. As of the adoption date, we recorded a liability of approximately $27.3 million for the payment of tax-related interest and penalties.

During the year ended December 31, 2007, we recorded a reduction in FIN 48 liabilities of approximately $10.4 million, including estimated tax-related interest and penalties.

See Note 5 to our consolidated financial statements included in this report for further information on income taxes.

YEAR ENDED DECEMBER 31, 2006 COMPARED TO YEAR ENDED DECEMBER 31, 2005

McDermott International, Inc. (Consolidated)

Revenues increased approximately 124.0%, or $2.3 billion, to $4.1 billion for year ended December 31, 2006, compared to $1.8 billion for the year ended December 31, 2005. Our Offshore Oil and Gas Construction segment generated a 30% increase in its revenues in the year ended December 31, 2007 compared to the year ended December 31, 2006, primarily attributable to its Middle East and Asia Pacific regions. Our Government Operations segment revenues increased approximately 5% in the year ended December 31, 2006, as compared to the year ended December 31, 2005.

Segment operating income increased $174.2 million from $224.6 million in the year ended December 31, 2005 to $398.8 million in the year ended December 31, 2006. The segment operating income of our Offshore Oil and Gas Construction segment improved substantially in the year ended December 31, 2007, as compared to the year ended December 31, 2006. Our Government Operations segment operating income increased slightly in the year ended December 31, 2006, as compared to the year ended December 31, 2005.

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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 increased $56.6 million from $157.5 million in 2005 to $214.1 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 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 a 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.

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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 consisted primarily of B&W PGG and its subsidiaries, which were 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 PGG and its subsidiaries, which were reconsolidated into our results effective February 22, 2006 and include approximately ten months’ results in the year ended December 31, 2006. B&W PGG’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 $6.2 million to $12.6 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 the Chapter 11 Bankruptcy 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 Secured Notes in June 2006, partially offset by higher interest and associated amortization and costs on our credit facilities.

We recorded other income from a U.S. federal tax-related interest expense adjustment for the year ended December 31, 2006, totaling approximately $13.2 million, attributable to a settlement we 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, we completed a tender offer and used current cash on hand to purchase the entire $200 million in aggregate principal amount outstanding of the 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 PGG retired its $250 million promissory note issued in 2006, as part of the 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.

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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 $26.4 million to $35.2 million, while income before provision for income taxes increased $138.4 million to $352.8 million. Our effective tax rate for the year ended December 31, 2006 was approximately 10%, which was primarily due to the valuation allowance adjustment discussed below.

For the year ended December 31, 2006, we reversed $78.1 million of the deferred tax asset valuation allowance recorded against various 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 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 federal deferred tax asset valuation allowance, discussed above, through current period earnings in 2006 by recording a credit to our provision for income taxes.

We completed a reorganization of our U.S. tax 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 our U.S. offshore oil and gas construction business were combined with our other U.S. subsidiaries in a single consolidated U.S. group. In 1995, substantially all our offshore oil and gas construction assets were acquired by our Offshore Oil and Gas Construction segment in conjunction with its acquisition of Offshore Pipelines, Inc. (“OPI”). As a result of the acquisition of OPI, MII’s ownership interest in the common stock of JRMSA was reduced to approximately 64%, with the remaining 36% being publicly traded. The results of our Offshore Oil and Gas Construction segment’s U.S. subsidiaries were consequently no longer part of our consolidated U.S. group. In 1999, MII acquired all of the remaining publicly held common stock of JRMSA, such that MII owned 100%. A restructuring to achieve the reconsolidation of the U.S. subsidiaries of our Offshore Oil and Gas Construction segment and our other U.S. subsidiaries was not feasible until 2006, attributable in part to long-running asbestos liability claims against B&W PGG, which ultimately led B&W PGG to file for Chapter 11 bankruptcy protection. In February 2006, B&W PGG emerged from Chapter 11 bankruptcy protection and was reconsolidated into our results. Subsequent to B&W PGG’s emergence from bankruptcy, action was taken to recombine our U.S. subsidiary 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, our current earnings reflect a tax benefit, 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 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 a 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.

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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:

	Income (loss) from Continuing Operations before Provision for Income Taxes						Provision for (Benefit from) Income Taxes						Effective Tax Rate
	2006			2005			2006			2005			2006			2005
	(In thousands)						(In thousands)

Primarily United States:
McDermott Incorporated	$	169,674		$	67,114		$	84,594		$	(17,666	)		49.86	%		(26.32	)%
J. Ray McDermott Holdings, LLC		(79,764	)		(10,364	)		(93,040	)		1,699			116.64	%		(16.39	)%
Subtotal		89,910			56,750			(8,446	)		(15,967	)		(9.39	%)		(28.14	)%
Non-United States:
International Subsidiaries		262,906			157,660			43,641			24,794			16.60	%		15.73	%

Total	$	352,816		$	214,410		$	35,195		$	8,827			9.98	%		4.12	%

Our U.S. subsidiaries are subject to U.S. federal income tax at a rate of 35%. The effective tax rate is primarily affected by applicable state income taxes on our profitable U.S. subsidiaries, as well as the items discussed below. In the year ended December 31, 2006, we reached a settlement in a tax dispute with U.S. 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 our 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 carryforwards that may expire in the future prior to being utilized. We also recorded a net provision for income taxes in the year ended December 31, 2006 of approximately $9 million associated with potential U.S. income tax issues.

The effective tax rate for the year ended December 31, 2005 was impacted by the Chapter 11 Bankruptcy settlement adjustment recorded in that period, which generated little or no associated U.S income tax effect, and the valuation allowance adjustment discussed above.

See Note 5 to our consolidated financial statements included in this report for further information on income 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

Offshore Oil and Gas Construction

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eliminate a synthetic letter of credit facility, (2) reduce the commitment fees and applicable margins for revolving loans and letters of credit and (3) eliminate the limitation on revolving credit borrowings. The JRMSA Credit Facility now consists of a five-year, $500 million revolving credit facility (under which all of the credit capacity may be used for the issuance of letters of credit and revolver borrowings), which matures on June 6, 2011. The proceeds of the JRMSA Credit Facility are available for working capital needs and other general corporate purposes of our Offshore Oil and Gas Construction segment.

JRMSA’s obligations under the JRMSA Credit Facility are unconditionally guaranteed by substantially all of our wholly owned subsidiaries comprising our Offshore Oil and Gas Construction segment and secured by liens on substantially all the assets of those subsidiaries (other than cash, cash equivalents, equipment and certain foreign assets), including their major marine vessels. JRMSA is permitted to prepay amounts outstanding under the JRMSA Credit Facility at any time without penalty. Other than customary mandatory prepayments on certain contingent events, the JRMSA Credit Facility requires only interest payments on a quarterly basis until maturity. Loans outstanding under the JRMSA Credit Facility bear interest at either the Eurodollar rate plus a margin ranging from 1.00% to 1.75% per year or the base rate plus a margin ranging from 0.00% to 0.75% per year. If there had been borrowings under this facility, the applicable interest rate at December 31, 2007 would have been 6.35% per year. The applicable margin for revolving loans varies depending on credit ratings of the JRMSA Credit Facility. JRMSA is charged a commitment fee on the unused portions of the JRMSA Credit Facility, and that fee varies between 0.25% and 0.375% per year depending on credit ratings of the JRMSA Credit Facility. Additionally, JRMSA is charged a letter of credit fee of between 1.00% and 1.75% per year with respect to the amount of each letter of credit issued under the JRMSA Credit Facility depending on credit ratings of the JRMSA Credit Facility. An additional 0.125% annual fee is charged on the amount of each letter of credit issued under the JRMSA Credit Facility.

The JRMSA 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. A comparison of the key financial covenants and current compliance at December 31, 2007 is as follows:

	Required	Actual
	(In millions, except ratios)

Maximum leverage ratio	2.50	0.05
Minimum interest coverage ratio	3.50	72.49
Limitation on capital expenditures: general	$125	$99.1
Limitation on capital expenditures: fab yards	$45	$45.0

At December 31, 2007, JRMSA was in compliance with all of the covenants set forth in the JRMSA Credit Facility.

At December 31, 2007, there were no borrowings outstanding and letters of credit issued under the JRMSA Credit Facility totaled $279.2 million. In addition, JRMSA and its subsidiaries had $172.8 million in outstanding unsecured letters of credit under separate arrangements with financial institutions at December 31, 2007. At December 31, 2007, there was $220.8 million available for borrowings or to meet letter of credit requirements under the JRMSA Credit Facility.

In December 2005, JRMSA, as guarantor, and its subsidiary, J. Ray McDermott Middle East, Inc. (“JRM Middle East”), entered into a $105.2 million unsecured performance guarantee issuance facility with a syndicate of commercial banking institutions to provide credit support for bank guarantees issued in connection with three major projects. The outstanding amount under this facility is included in the $172.8 million outstanding referenced above. On February 3, 2008, JRM Middle East entered into a new $88.8 million unsecured performance guarantee issuance facility to replace the $105.2 million facility, which it terminated on February 14, 2008. This new facility continues to provide credit support for bank guarantees for the duration of the three projects. On an annualized basis, the average commission rate of the new facility is less than 1.5%, compared to less than 4.5% for the former facility. JRMSA is also a guarantor of the new facility.

On July 27, 2007, we completed our acquisition of substantially all of the assets of Secunda International Limited, including 14 harsh-weather, multi-functional vessels, with capabilities which include subsea construction, pipelay,

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cable lay and dive support, as well as its shore-based operations, for approximately $263 million in cash and recognition of approximately $10 million of liabilities, including approximately $4 million related to deferred income taxes. We recorded goodwill of approximately $29 million in connection with this acquisition, none of which will be deductible for tax purposes. In addition to the goodwill, we recorded identifiable intangible assets of approximately $12 million related to contractual customer relationships, which have a weighted-average amortization period of 3.6 years.

Based on the liquidity position of our Offshore Oil and Gas Construction segment, we believe this segment has sufficient cash and letter of credit and borrowing capacity to fund its operating requirements for at least the next 12 months.

Government Operations

On December 9, 2003, one of our subsidiaries, BWX Technologies, Inc. entered into a senior unsecured credit facility with a syndicate of lenders (the “BWXT Credit Facility”), which is currently scheduled to mature March 18, 2010. On October 29, 2007, the BWXT Credit Facility was amended to reduce the applicable margins for revolving loans and letters of credit. This facility provides for borrowings and issuances of letters of credit in an aggregate amount of up to $135 million. The proceeds of the BWXT Credit Facility are available for working capital needs and other general corporate purposes of our Government Operations segment.

The BWXT Credit Facility requires BWXT to comply with various financial and nonfinancial covenants and reporting requirements. The financial covenants require maintenance of a maximum leverage ratio, a minimum fixed charge coverage ratio and a maximum debt to capitalization ratio within our Government Operations segment. A comparison of the key financial covenants and current compliance at December 31, 2007 is as follows:

	Required	Actual

Maximum leverage ratio	2.0	0.27
Minimum fixed charge coverage ratio	1.1	8.92
Maximum debt to capitalization	0.4	0.00

At December 31, 2007, BWXT was in compliance with all of the covenants set forth in the BWXT Credit Facility.

Loans outstanding under the BWXT Credit Facility bear interest at either the Eurodollar rate plus a margin ranging from 1.25% to 1.75% per year or the base rate plus a margin ranging from 0.25% and 0.75% per year. The applicable margin for revolving loans varies depending on the leverage ratio of our Government Operations segment as of the last day of the preceding fiscal quarter. If there had been borrowings under this facility, the applicable interest rate at December 31, 2007 would have been 5.85% per year. 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 1.25% and 1.75% per year with respect to the amount of each letter of credit issued, depending on the leverage ratio of our Government Operations segment as of the last day of the preceding fiscal quarter. An additional 0.125% per year fee is charged on the amount of each letter of credit issued.

At December 31, 2007, there were no borrowings outstanding and letters of credit issued under the BWXT Credit Facility totaled $48.0 million. At December 31, 2007, there was $87.0 million available for borrowings or to meet letter of credit requirements under the BWXT Credit Facility.

On May 1, 2007, we completed our stock acquisition of Marine Mechanical Corporation for approximately $72 million in cash and recognition of liabilities in excess of the liabilities directly assumed from Marine Mechanical Corporation of approximately $16 million, primarily related to deferred income taxes. We recorded goodwill of approximately $39 million in connection with this acquisition, none of which will be deductible for tax purposes.

Based on the liquidity position of our Government Operations segment, we believe this segment has sufficient cash and letter of credit and borrowing capacity to fund its operating requirements for at least the next 12 months.

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Power Generation Systems

On February 22, 2006, one of our subsidiaries, Babcock & Wilcox Power Generation Group, Inc. entered into a senior secured credit facility with a syndicate of lenders (the “B&W PGG Credit Facility”). During July 2007, the B&W PGG Credit Facility was amended to, among other things, (1) increase the revolving credit facility by $200 million to $400 million and eliminate a synthetic letter of credit facility and (2) reduce the commitment fees and applicable margins for revolving loans and letters of credit. The entire credit availability under the B&W PGG Credit Facility may be used for the issuance of letters of credit or for borrowings to fund working capital requirements for our Power Generation System segment. The B&W PGG Credit Facility also originally included a commitment by certain of the lenders to loan up to $250 million in term debt to refinance the $250 million promissory note payable to a trust under the Chapter 11 plan of reorganization. On November 30, 2006, B&W PGG drew down $250 million on this term loan under the B&W PGG Credit Facility. On April 12, 2007, the $250 million term loan was retired without penalty. This payment was made using cash on hand, including the $272 million federal tax refund received on April 12, 2007.

B&W PGG’s obligations under the B&W PGG Credit Facility are unconditionally guaranteed by all of our domestic subsidiaries included in our Power Generation Systems segment and secured by liens on substantially all the assets of those subsidiaries, excluding cash and cash equivalents.

Loans outstanding under the revolving credit subfacility bear interest at either the Eurodollar rate plus a margin ranging from 1.00% to 1.75% per year or the base rate plus a margin ranging from 0.00% to 0.75% per year. If there had been borrowings under this facility, the applicable interest rate at December 31, 2007 would have been 5.85% per year. The applicable margin for revolving loans varies depending on credit ratings of the B&W PGG Credit Facility. B&W PGG is charged a commitment fee on the unused portion of the B&W PGG Credit Facility, and that fee varies between 0.25% and 0.375% per year depending on credit ratings of the B&W PGG Credit Facility. Additionally, B&W PGG is charged a letter of credit fee of between 1.00% and 1.75% per year with respect to the amount of each letter of credit issued under the B&W PGG Credit Facility. An additional 0.125% per year fee is charged on the amount of each letter of credit issued under the B&W PGG Credit Facility.

The B&W PGG Credit Facility only requires interest payments on a quarterly basis until maturity. Amounts outstanding under the B&W PGG Credit Facility may be prepaid at any time without penalty.

The B&W PGG Credit Facility contains customary financial covenants within our Power Generation Systems segment, including maintenance of a maximum leverage ratio and a minimum interest coverage ratio, and covenants that, among other things, restrict the ability of this segment 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 PGG Credit Facility also contains customary events of default. A comparison of the key financial covenants and current compliance at December 31, 2007 is as follows:

	Required	Actual
	(In millions, except ratios)

Maximum leverage ratio	3.25	0.03
Minimum interest coverage ratio	3.25	19.88
Limitation on capital expenditures	$45	$34.5

At December 31, 2007, B&W PGG was in compliance with all of the covenants set forth in the B&W PGG Credit Facility.

As of December 31, 2007, there were no outstanding borrowings and letters of credit issued under the B&W PGG Credit Facility totaled $225.2 million. At December 31, 2007, there was $174.8 million available for borrowings or to meet letter of credit requirements under the B&W PGG Credit Facility.

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Based on the liquidity position of our Power Generation Systems segment, we believe this segment 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 our Canadian subsidiaries has received notice of a possible warranty claim on one of its projects on a contract executed in 1998. This situation relates to technical issues concerning components associated with nuclear steam generators. Data collection and analysis, which can only be performed at specific time periods when the power plant is scheduled to be off-line for maintenance, is continuing. The next outage of this facility is scheduled for the spring of 2008 when additional testing will be performed. These tests require detailed engineering study and comprehensive analysis. This project included a limited-term performance bond totaling approximately $140 million for which we entered into an indemnity arrangement with the surety underwriters. At this time, our subsidiary continues to analyze the facts and circumstances surrounding this issue. It is possible that our subsidiary may incur warranty costs in excess of amounts provided for as of December 31, 2007. It is also possible that a claim could be initiated by our subsidiary’s customer against the surety underwriter should certain events occur. If such a claim were successful, the surety could seek to recover from our subsidiary the costs incurred in satisfying the customer claim. If the surety seeks recovery from our subsidiary, we believe that our 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 continuing to review the funded status of our various domestic defined benefit pension plans with the stated objective of fully funding these plans by 2010. We are exploring various alternatives, including potential additional contributions and liability driven investment strategies such as annuitization of certain plan liabilities and asset/liability duration matching. Some of these alternative strategies could have a significant impact on our consolidated financial position and operating cash flow.

In July 2007, we and our rated subsidiaries received upgraded ratings from both major corporate credit rating services, Standard & Poor’s Rating Services (“S&P”) and Moody’s Investors Service (“Moody’s”). Included among these ratings actions, our corporate credit rating at S&P was raised to BB from B+, with a stable outlook, and our corporate family rating at Moody’s was raised to Ba3 from B1, also with a stable outlook. As a result of recent improved operating performance, stronger liquidity and now higher credit ratings, we were able to amend the JRM Credit Facility and the B&W PGG Credit Facility, as mentioned above, to, among other things, reduce fees and expenses.

At December 31, 2007, we had total restricted cash and cash equivalents of $64.8 million. The restricted cash and cash equivalents include the following: $0.7 million, which is required to meet reinsurance reserve requirements of our captive insurance companies, and $64.1 million, which is held in restricted foreign accounts.

Certain of our subsidiaries are restricted in their ability to transfer funds to MII. Such restrictions principally arise from debt covenants, insurance regulations, national currency controls and the existence of minority shareholders. We refer to the proportionate share of net assets, after intercompany eliminations, that may not be transferred to MII as a result of these restrictions as “restricted net assets.” At December 31, 2007, the restricted net assets of our consolidated subsidiaries were approximately $596 million.

At December 31, 2007 and December 31, 2006, our balance in cash and cash equivalents on our consolidated balance sheets included approximately $20.2 million and $18.0 million, respectively, in adjustments for book overdrafts, with a corresponding increase in accounts payable for these overdrafts.

Our working capital, excluding restricted cash and cash equivalents, increased approximately $410.7 million from a negative $414.5 million at December 31, 2006 to a negative $3.8 million at December 31, 2007, primarily attributable to the collection of approximately $274 million of income taxes receivable, which was classified as long-term at December 31, 2006, and an overall increase in net operating activities in the year ended December 31, 2007, as discussed below. These increases were partially offset by the cash we used to fund the acquisition of substantially all the assets of Secunda International Limited and our acquisition of Marine Mechanical Corporation.

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Our net cash provided by operations was approximately $1,316.9 million for the year ended December 31, 2007, compared to approximately $228.1 million for the year ended December 31, 2006. This increase was primarily attributable to higher net income, receipt of the TXU settlement and receipt of $274 million of income tax refunds during the year ended December 31, 2007. Additionally, during the year ended December 31, 2006, we made payments in connection with the Chapter 11 plan of reorganization, which reduced our net cash provided by operations for that year.

Our net cash provided by (used in) investing activities changed by approximately $989.1 million to net cash used in investing activities of $678.7 million for the year ended December 31, 2007, compared to net cash provided by investing activities of $310.4 million for the year ended December 31, 2006. This change was primarily attributable to the Marine Mechanical Corporation and Secunda International Limited acquisitions, increased capital expenditures and an increase in our net activity for available-for-sale securities for the year ended December 31, 2007. Also contributing to the change was the cash acquired from our reconsolidation of several subsidiaries in our Power Generation Systems segment during the year ended December 31, 2006.

Our net cash provided by (used in) financing activities changed by approximately $287.0 million to net cash used in financing activities of $243.3 million in the year ended December 31, 2007, compared to net cash provided by financing activities of $43.7 million in the year ended December 31, 2006, primarily attributable to the retirement of the $250 million term loan in April 2007.

At December 31, 2007, we had investments with a fair value of $462.2 million. Our investment portfolio consists primarily of investments in government obligations and other highly liquid money market instruments. As of December 31, 2007, we had pledged approximately $31 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, 2007 under current contractual obligations are as follows:

	Total		Less than 1 Year		1-3 Years		3-5 Years		After 5 Years
	(In thousands)
Long-term debt	$	17,208	$	6,599	$	5,060	$	4,810	$	739
Operating leases	$	47,597	$	17,660	$	16,868	$	8,088	$	4,981
Vessel charters	$	10,227	$	10,227	$	-	$	-	$	-
Take-or-pay contract	$	3,600	$	1,800	$	1,800	$	-	$	-
Insurance premium adjustment	$	1,250	$	1,250	$	-	$	-	$	-

We have interest payments on our long-term debt obligations above as follows: less than one year, $0.8 million; one to three years, $0.6 million; three to five years, $0.2 million; and after five years, zero, for a total of $1.6 million. These obligations are based on the debt outstanding at December 31, 2007 and the stated interest rates. In addition, we expect to contribute approximately $156.1 million to our domestic pension plans, which includes approximately $77.4 million for our Power Generation Systems segment, $62.8 million for our Government Operations segment, $2.2 million for our Offshore Oil and Gas Construction segment and $13.7 million for Corporate, respectively, and $13.0 million to our other postretirement benefit plans in 2008.

Our contingent commitments under letters of credit currently outstanding expire as follows:

Total		Less than 1 Year		1-3 Years		3-5 Years		Thereafter
(In thousands)
$	725,094	$	468,097	$	161,981	$	88,439	$	6,577

As discussed in Note 5 to our consolidated financial statements included in this report, effective January 1, 2007, the company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109.” At December 31, 2007, the company had a liability for

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unrecognized tax benefits and an accrual for the payment of related interest and penalties totaling $85 million, of which between $6 million and $8 million is expected to be paid within one year. For the remaining liability, due to the uncertainties related to these tax matters, we are unable to make a reasonably reliable estimate as to when cash settlement with a taxing authority will occur.

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 PGG Credit Facility (see Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources”). At December 31, 2007, we had no outstanding borrowings under any of these credit facilities. 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, 2007:																				Fair Value at
	Years Ending December 31,																			December 31,
	2008			2009			2010			2011			2012		Thereafter			Total		2007

Investments	$	392,353		$	59,444		$	219		$	-		$	-	$	9,161		$	461,177	$	462,161
Average Interest Rate		4.95	%		4.61	%		2.58	%		-			-		5.18	%
Long-term Debt – Fixed Rate	$	4,250		$	4,250		$	-		$	-		$	-	$	-		$	8,500	$	8,604
Average Interest Rate		6.80	%		6.80	%		-			-			-		-

At December 31, 2006:																				Fair Value at
	Years Ending December 31,																			December 31
	2007			2008			2009			2010			2011		Thereafter			Total		2006

Investments	$	276,385		$	8,286		$	-		$	1,233		$	-	$	7,651		$	293,555	$	294,085
Average Interest Rate		4.86	%		4.75	%		-			2.58	%		-		5.52	%
Long-term Debt –Fixed Rate	$	4,250		$	4,250		$	4,250		$	-		$	-	$	225		$	12,975	$	13,168
Average Interest Rate		6.80	%		6.80	%		6.80	%		-			-		10.0	%

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Exchange Rate Sensitivity

The following table provides information about our foreign currency forward contracts outstanding at December 31, 2007 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. The average contractual exchange rates are expressed using market convention, which is dependent on the currencies being bought and sold under the forward contract.

Forward Contracts to Purchase Foreign Currencies in U.S. Dollars (in thousands)

	Year Ending		Fair Value at			Average Contractual
Foreign Currency	December 31, 2008		December 31, 2007			Exchange Rate

Euros	$	140,918	$	4,826			1.4200
Pound Sterling	$	20,895	$	(278	)		2.0302
Pound Sterling (selling Euros)	$	15,144	$	(1,075	)		0.6896
Canadian Dollars (selling Pound Sterling)	$	13,115	$	810			2.0988
Canadian Dollars	$	7,193	$	378			1.0418
Swedish Krona	$	5,872	$	162			6.7034
Japanese Yen (selling Canadian Dollars)	$	2,863	$	164			118.0932
Pound Sterling (selling South African Rand)	$	797	$	(4	)		13.6965
Thai Baht	$	785	$	24			31.5276
Danish Krone	$	546	$	2			5.1495
Euros (selling South African Rand)	$	126	$	1			10.2250

	Year Ending		Fair Value at			Average Contractual
Foreign Currency	December 31, 2009		December 31, 2007			Exchange Rate

Canadian Dollars	$	38,336	$	336			1.0047
Euros	$	21,747	$	394			1.4247
Pound Sterling	$	7,046	$	(220	)		2.0058
Danish Krone	$	504	$	17			5.3160
Pound Sterling (selling Euros)	$	375	$	(28	)		0.6918

	Year Ending		Fair Value at			Average Contractual
Foreign Currency	December 31, 2010		December 31, 2007			Exchange Rate

Canadian Dollars	$	47,351	$	182			1.0093
Japanese Yen (selling Canadian Dollars)	$	5,278	$	(147	)		101.8480

	Year Ending		Fair Value at			Average Contractual
Foreign Currency	December 31, 2011		December 31, 2007			Exchange Rate

Canadian Dollars	$	34,612	$	138			1.0139
Japanese Yen (selling Canadian Dollars)	$	5,184	$	(146	)		98.3035

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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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 sheets of McDermott International, Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, comprehensive income, stockholders' equity (deficit), and cash flows for the years then ended. Our audits also included the 2007 and 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 audits. The consolidated financial statements and financial statement schedules of the Company for the year ended December 31, 2005, before the effects of the retrospective adjustments for the discontinued operations discussed in Note 3, the change in accounting for drydocking costs described in Note 1, and the two-for-one and three-for-two common stock splits discussed in Note 9 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 audits 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 audits provide a reasonable basis for our opinion.

In our opinion, such 2007 and 2006 consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, such 2007 and 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 21 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 Notes 1 and 21, 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 consolidated financial statements for the operations discontinued in 2006 discussed in Note 3, the change in accounting in 2007 for drydocking costs described in Note 1, and the two-for-one and three-for-two common stock splits in 2007 and 2006, respectively, discussed in Note 9 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 drydocking costs and comparing the retrospectively adjusted amounts per the 2005 financial statements to such analysis, (2) comparing previously reported amounts to the previously issued financial statements for 2005, (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 and drydocking costs to independent supporting documentation, (5) comparing the amounts shown in the earnings per share disclosures for 2006 and 2005 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 splits 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 consolidated financial statements and financial statement schedules of the Company other than with respect to

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the retrospective adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2005 consolidated financial statements and financial statement schedules taken as a whole.

As discussed in Note 5 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” as of January 1, 2007. 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 Company's internal control over financial reporting as of December 31, 2007, 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 February 27, 2008 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2008

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of McDermott International, Inc.:

In our opinion, the consolidated statements of income, comprehensive income, shareholders’ deficit and cash flows for the year ended December 31, 2005, before the effects of the adjustments to retrospectively reflect the change in accounting for drydock costs described in Note 1, the adjustments to retrospectively reflect the discontinued operations described in Note 3 and the adjustments to retrospectively reflect the three-for-two and two-for-one stock splits described in Note 9, present fairly, in all material respects, the results of operations and cash flows of McDermott International, Inc. and its subsidiaries (the "Company") for the year ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America (the 2005 consolidated financial statements before the effects of the adjustments discussed in Notes 1, 3 and 9 are not presented herein). In addition, in our opinion, the financial statement schedule for the year 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 schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit, 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 audit provides a reasonable basis for our opinion.

We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively reflect the change in accounting for drydock costs described in Note 1, the adjustments to retrospectively reflect the discontinued operations described in Note 3 and the adjustments to retrospectively reflect the three-for-two and two-for-one stock splits described in Note 9 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2006

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McDERMOTT INTERNATIONAL, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007		2006
	(In thousands)

ASSETS
Current Assets:
Cash and cash equivalents	$	1,001,394	$	600,843
Restricted cash and cash equivalents (Note 1)		64,786		106,674
Investments (Note 15)		300,092		172,171
Accounts receivable – trade, net		770,024		668,310
Accounts and notes receivable – unconsolidated affiliates		2,303		29,825
Accounts receivable – other		71,162		48,041
Contracts in progress		194,292		230,146
Inventories (Note 1)		95,208		77,769
Deferred income taxes		160,783		180,234
Other current assets		97,456		39,461

Total Current Assets		2,757,500		2,153,474

Property, Plant and Equipment		2,004,138		1,525,187
Less accumulated depreciation		1,090,400		1,011,693

Net Property, Plant and Equipment		913,738		513,494

Investments (Note 15)		162,069		121,914

Goodwill		158,533		89,226

Deferred Income Taxes		134,292		260,341

Long-Term Income Tax Receivable		8,745		299,786

Investments in Unconsolidated Affiliates		62,241		52,801

Other Assets		214,368		142,726

TOTAL	$	4,411,486	$	3,633,762

See accompanying notes to consolidated financial statements.

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McDERMOTT INTERNATIONAL, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007			2006
	(In thousands)

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Notes payable and current maturities of long-term debt	$	6,599		$	257,492
Accounts payable		455,659			407,094
Accrued employee benefits		343,812			246,182
Accrued liabilities – other		175,557			185,762
Accrued contract cost		93,281			110,992
Advance billings on contracts		1,463,223			1,116,118
Accrued warranty expense		101,330			79,077
Income taxes payable		57,071			58,557

Total Current Liabilities		2,696,532			2,461,274

Long-Term Debt		10,609			15,242

Accumulated Postretirement Benefit Obligation		96,253			100,316

Self-Insurance		82,525			84,704

Pension Liability		188,748			372,504

Other Liabilities		169,814			156,621

Commitments and Contingencies (Note 11)

Stockholders’ Equity:
Common stock, par value $1.00 per share, authorized 400,000,000 shares; issued 231,722,659 and 227,794,618 at December 31, 2007 and 2006, respectively		231,723			227,795
Capital in excess of par value		1,145,829			1,100,384
Accumulated earnings (deficit)		135,289			(458,886	)
Treasury stock at cost, 5,852,248 and 6,025,418 at December 31, 2007 and 2006, respectively		(63,903	)		(60,581	)
Accumulated other comprehensive loss		(281,933	)		(365,611	)

Total Stockholders’ Equity		1,167,005			443,101

TOTAL	$	4,411,486		$	3,633,762

See accompanying notes to consolidated financial statements.

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McDERMOTT INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2007			2006			2005
	(In thousands, except shares and per share amounts)

Revenues	$	5,631,610		$	4,120,141		$	1,839,740
Costs and Expenses:
Cost of operations		4,500,897			3,362,758			1,436,107
Gains on settlements and curtailments of pension plans		-			-			(1,390	)
(Gains) losses on asset disposals and impairments – net		(8,371	)		15,042			(6,554	)
Selling, general and administrative expenses		464,611			388,524			220,380
		4,957,137			3,766,324			1,648,543

Equity in Income of Investees		41,724			37,524			40,523

Operating Income		716,197			391,341			231,720

Other Income (Expense):
Interest income		61,980			53,562			21,046
Interest expense		(22,520	)		(30,348	)		(31,820	)
IRS interest expense adjustment		-			5,719			-
Loss on Babcock & Wilcox Power Generation Group, Inc. bankruptcy settlement		-			-			(5,887	)
Loss on early retirement of debt		-			(53,708	)		-
Other expense – net		(10,192	)		(13,750	)		(649	)
		29,268			(38,525	)		(17,310	)

Income from Continuing Operations before Provision for Income Taxes		745,465			352,816			214,410

Provision for Income Taxes		137,637			35,195			8,827

Income from Continuing Operations		607,828			317,621			205,583

Income from Discontinued Operations		-			12,894			104

Net Income	$	607,828		$	330,515		$	205,687

Earnings per Common Share:
Basic:
Income from Continuing Operations	$	2.72		$	1.46		$	1.00
Income from Discontinued Operations	$	0.00		$	0.06		$	0.00
Net Income	$	2.72		$	1.52		$	1.00
Diluted:
Income from Continuing Operations	$	2.66		$	1.39		$	0.94
Income from Discontinued Operations	$	0.00		$	0.06		$	0.00
Net Income	$	2.66		$	1.45		$	0.94

Shares used in the computation of earnings per share (Note 20):
Basic		223,511,880			217,752,454			205,137,664
Diluted		228,742,522			227,718,784			218,337,530

See accompanying notes to consolidated financial statements.

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McDERMOTT INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2007			2006			2005
	(In thousands)

Net Income	$	607,828		$	330,515		$	205,687

Other Comprehensive Income (Loss):
Currency translation adjustments:
Foreign currency translation adjustments		13,924			10,607			(2,233	)
Reclassification adjustment for impairment of investment		-			16,438			-
Reconsolidation of Babcock & Wilcox Power Generation Group, Inc.		-			15,833			-
Unrealized gains (losses) on derivative financial instruments:
Unrealized gains (losses) on derivative financial instruments		15,658			10,600			(6,889	)
Reclassification adjustment for (gains) losses included in net income		(4,226	)		(30	)		3,491
Reconsolidation of Babcock & Wilcox Power Generation Group, Inc.		-			(269	)		-
Unrecognized gains on benefit obligations:
Unrecognized gains arising during the period		32,272			-			-
Amortization of losses included in net income		24,892			-			-
Amortization of losses included in retained earnings		704			-			-
Minimum pension liability adjustment:
Minimum pension liability adjustment		-			98,371			(86,953	)
Reconsolidation of Babcock & Wilcox Power Generation Group, Inc.		-			15,578			-
Unrealized gains (losses) on investments:
Unrealized gains (losses) arising during the period		629			1,326			(747	)
Reclassification adjustment for net (gains) losses included in net income		(175	)		(7	)		5

Other Comprehensive Income (Loss)		83,678			168,447			(93,326	)

Comprehensive Income	$	691,506		$	498,962		$	112,361

See accompanying notes to consolidated financial statements.

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McDERMOTT INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

													Accumulated						Total
							Capital In			Accumulated			Other						Stockholders’
	Common Stock						Excess of			Earnings			Comprehensive			Treasury			Equity
	Shares			Par Value(1)			Par Value(1)			(Deficit)			Loss			Stock			(Deficit)
	(In thousands, except for share amounts)
Balance December 31, 2004, as reported		208,682,178		$	208,682		$	982,934		$	(1,060,908	)	$	(327,526	)	$	(64,625	)	$	(261,443	)
Change in accounting principle (Note 1)		-			-			-			58,795			-			-			58,795
Balance December 31, 2004, as adjusted		208,682,178			208,682			982,934			(1,002,113	)		(327,526	)		(64,625	)		(202,648	)

Net income		-			-			-			205,687			-			-			205,687
Minimum pension liability, net of tax		-			-			-			-			(86,953	)		-			(86,953	)
Unrealized loss on investments		-			-			-			-			(742	)		-			(742	)
Translation adjustments		-			-			-			-			(2,233	)		-			(2,233	)
Unrealized loss on derivatives		-			-			-			-			(3,398	)		-			(3,398	)
Exercise of stock options		11,431,596			11,432			49,514			-			-			-			60,946
Vesting of deferred stock units		15,000			15			(10	)		-			-			-			5
Restricted stock issuances – net		1,535,958			1,536			(938	)		-			-			-			598
Contributions to thrift plan		731,544			732			5,031			-			-			-			5,763
Issuance of treasury shares		(822,510	)		(823	)		(5,035	)		-			-			8,129			2,271
Stock-based compensation charges		-			-			3,911			-			-			-			3,911
Balance December 31, 2005		221,573,766			221,574			1,035,407			(796,426	)		(420,852	)		(56,496	)		(16,793	)

Net income		-			-			-			330,515			-			-			330,515
Cumulative adjustment for conversion to equity method (Note 4)		-			-			-			7,025			-			-			7,025
Minimum pension liability, net of tax		-			-			-			-			113,949			-			113,949
Unrealized gain on investments		-			-			-			-			1,319			-			1,319
Translation adjustments		-			-			-			-			42,878			-			42,878
Unrealized gain on derivatives		-			-			-			-			10,301			-			10,301
Exercise of stock options		5,367,176			5,367			13,726			-			-			2,410			21,503
Restricted stock issuances – net		34,530			35			(20	)		-			-			(38	)		(23	)
Contributions to thrift plan		473,860			474			8,693			-			-			-			9,167
Purchase of treasury shares		253,920			254			2,758			-			-			(5,596	)		(2,584	)
Stock-based compensation charges		-			-			39,161			-			-			-			39,161
Reclassification of forfeited shares		91,366			91			770			-			-			(861	)		-
Cash in lieu of fractional shares resulting from stock split (Note 9)		-			-			(111	)		-			-			-			(111	)
Adoption of SFAS No. 158 (Note 7)		-			-			-			-			(113,206	)		-			(113,206	)
Balance December 31, 2006		227,794,618			227,795			1,100,384			(458,886	)		(365,611	)		(60,581	)		443,101

Net income		-			-			-			607,828			-			-			607,828
Adoption of FIN 48 (Note 5)		-			-			-			(11,965	)		-			-			(11,965	)
Adoption of SFAS No. 158 (Note 7)		-			-			-			(1,688	)		704			-			(984	)
Amortization of benefit plan costs		-			-			-			-			24,892			-			24,892
Unrecognized gains on benefit obligations														32,272						32,272
Unrealized gain on investments		-			-			-			-			454			-			454
Translation adjustments		-			-			-			-			13,924			-			13,924
Unrealized gain on derivatives		-			-			-			-			11,432			-			11,432
Exercise of stock options		3,565,266			3,565			10,575			-			-			1,079			15,219
Restricted stock issuances – net		28,836			29			(25	)		-			-			-			4
Contributions to thrift plan		333,939			334			11,178			-			-			-			11,512
Purchase of treasury shares		-			-			-			-			-			(4,401	)		(4,401	)
Stock-based compensation charges		-			-			23,717			-			-			-			23,717

Balance December 31, 2007		231,722,659		$	231,723		$	1,145,829		$	135,289		$	(281,933	)	$	(63,903	)	$	1,167,005

(1) Amounts have been restated to reflect the stock splits effected in September 2007 and May 2006. See Note 9 for additional information.

See accompanying notes to consolidated financial statements.

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McDERMOTT INTERNATIONAL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2007			2006			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	607,828		$	330,515		$	205,687
Non-cash items included in net income:
Depreciation and amortization		95,989			61,000			44,266
(Income) loss of investees, net of dividends		120			1,644			(4,714	)
(Gains) losses on asset disposals and impairments – net		(8,371	)		15,042			(6,554	)
Gain on sale of business		-			(13,786	)		-
Premium on early retirement of debt		-			37,438			-
Provision for (benefit from) deferred taxes		89,624			179,467			(47,557	)
Amortization of pension and postretirement costs		50,957			-			-
Loss on Babcock & Wilcox Power Generation Group, Inc. (“B&W PGG”) bankruptcy settlement		-			-			5,887
Excess tax benefits from FAS 123(R) stock-based compensation		(877	)		(20,113	)		-
Other, net		21,726			14,660			20,324
Changes in assets and liabilities, net of effects from acquisition and divestitures:
Accounts receivable		(82,105	)		(49,858	)		2,568
Income taxes receivable		255,165			(284,494	)		-
Accounts payable		40,384			65,157			(46,664	)
Net contracts in progress and advance billings		382,184			330,996			96,010
Income taxes		(13,216	)		139,497			(14,570	)
Accrued and other current liabilities		(14,305	)		81,060			(52,390	)
Pension liability and accrued postretirement and employee benefits		(74,365	)		(119,114	)		46,803
Payment of the B&W PGG bankruptcy settlement		-			(605,000	)		-
Other, net		(33,790	)		64,031			5,851
NET CASH PROVIDED BY OPERATING ACTIVITIES		1,316,948			228,142			254,947
CASH FLOWS FROM INVESTING ACTIVITIES:
Decrease in restricted cash and cash equivalents		41,888			48,298			22,981
Purchases of property, plant and equipment		(233,289	)		(132,704	)		(67,595	)
Acquisition of businesses, net of cash acquired		(334,457	)		-			-
Net (increase) decrease in available-for-sale securities		(159,350	)		212,082			(457,270	)
Proceeds from asset disposals		11,223			21,712			17,223
Cash acquired from the reconsolidation of B&W PGG		-			164,200			-
Other, net		(4,696	)		(3,193	)		(6,095	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(678,681	)		310,395			(490,756	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of long-term debt		-			250,000			-
Payment of long-term debt		(255,749	)		(238,615	)		(66,984	)
Payment of debt issuance costs		(3,625	)		(10,170	)		(949	)
Issuance of common stock		15,219			19,647			60,951
Excess tax benefits from FAS 123(R) stock-based compensation		877			20,113			-
Other, net		4			2,718			2,779
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(243,274	)		43,693			(4,203	)
EFFECTS OF EXCHANGE RATE CHANGES ON CASH		5,558			(650	)		(44	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		400,551			581,580			(240,056	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		600,843			19,263			259,319
CASH AND CASH EQUIVLENTS AT END OF PERIOD	$	1,001,394		$	600,843		$	19,263

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized)	$	28,066		$	28,588		$	37,720
Income taxes (net of refunds) (1)	$	(208,194	)	$	63,357		$	44,961

(1)	Income tax payments are gross amounts and do not include reimbursements received from B&W PGG of $3.7 million for the year ended December 31, 2005.

See accompanying notes to consolidated financial statements.

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McDERMOTT INTERNATIONAL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2007

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 entities 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 entities that we do not control, but over which we have significant influence. We generally refer to these entities as “joint ventures.” 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. In these notes to consolidated financial statements, unless the context otherwise indicates, “we,” “us” and “our” mean MII and its consolidated subsidiaries.

We operate in three business segments: Offshore Oil and Gas Construction, Government Operations and Power Generation Systems.

Our business segments are outlined as follows:

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bankruptcy proceedings (the “Chapter 11 Bankruptcy”), which were commenced on February 22, 2000. Due to the Chapter 11 Bankruptcy, we did not consolidate the results of operations of these entities in our consolidated financial statements from February 22, 2000 through February 22, 2006. See Note 21 to our consolidated financial statements included in this report for more information on the Chapter 11 Bankruptcy.

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 these 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 $0.7 million, ($6.3) million and $2.1 million for the years ended December 31, 2007, 2006 and 2005, 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.

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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 that 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:

	December 31,
	2007		2006
	(In thousands)

Retainages expected to be collected in 2008	$	107,397	$	76,067
Retainages expected to be collected after one year		68,713		67,617
Total Retainages	$	176,110	$	143,684

We have included in accounts receivable – trade retainages expected to be collected in 2008. Retainages expected to be collected after one year are included in other assets. Of the long-term retainages at December 31, 2007, we anticipate collecting $33.8 million in 2009, $24.8 million in 2010 and $10.1 million in 2011.

Comprehensive Loss

The components of accumulated other comprehensive loss included in stockholders' equity are as follows:

	December 31,
	2007			2006
	(In thousands)
Currency Translation Adjustments	$	25,328		$	11,404
Net Unrealized Gain on Investments		984			530
Net Unrealized Gain on Derivative Financial Instruments		20,876			9,444
Unrecognized Losses on Benefit Obligations		(329,121	)		(386,989	)
Accumulated Other Comprehensive Loss	$	(281,933	)	$	(365,611	)

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.

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The following summarizes the changes in the carrying amount of accrued warranty:

	Year Ended December 31,
	2007			2006			2005
	(In thousands)

Balance at beginning of period	$	79,077		$	8,575		$	9,520
Reconsolidation of B&W PGG		-			48,329			-
Additions and adjustments		34,336			32,981			4,271
Charges		(12,083	)		(10,808	)		(5,216	)
Balance at end of period	$	101,330		$	79,077		$	8,575

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 Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” 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 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 of the decommissioning costs.

Substantially all of 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:

	Year Ended December 31,
	2007		2006		2005
	(In thousands)

Balance at beginning of period	$	8,395	$	7,556	$	6,800
Accretion		933		839		756
Balance at end of period	$	9,328	$	8,395	$	7,556

Research and Development

Research and development activities are related to development and improvement of new and existing products and equipment, as well as conceptual and engineering evaluation for translation into practical applications. We charge to cost of operations the costs of research and development unrelated to specific contracts as incurred. Research and development activities totaled $52.0 million, $45.2 million and $34.1 million in the years ended December 31, 2007, 2006 and 2005, respectively, which include $16.5 million, $26.5 million and $30.8 million, respectively, related to amounts paid for by our customers. The net expenses recognized in the years ended December 31, 2007, 2006 and 2005 totaled approximately $35.5 million, $18.7 million and $3.3 million, respectively.

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Inventories

We carry our inventories at the lower of cost or market. We determine cost principally on the first-in, first-out basis, except for certain materials inventories of our Power Generation Systems segment, for which we use the last-in, first-out (“LIFO”) method. We determined the cost of approximately 20% and 17% of our total inventories using the LIFO method at December 31, 2007 and 2006, respectively, and the total LIFO reserve at December 31, 2007 and 2006 was approximately $6.0 and $5.6 million, respectively. Inventories are summarized below:

	December 31,
	2007		2006
	(In thousands)
Raw Materials and Supplies	$	65,857	$	56,955
Work in Progress		10,757		7,453
Finished Goods		18,594		13,361
Total Inventories	$	95,208	$	77,769

Property, Plant and Equipment

We carry our property, plant and equipment at depreciated cost, less any impairment provisions.

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 $91.2 million, $60.5 million and $43.1 million for the years ended December 31, 2007, 2006 and 2005, 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 costs and regulatory fees, for our marine fleet over the period of time between drydockings, in accordance with the method commonly known as the accrue-in-advance method. Effective January 1, 2007 and pursuant to Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” we changed our accounting policy from the accrue-in-advance method to the deferral method. Under the deferral method, we recognize drydocking costs as a prepaid asset when incurred and amortize the costs over the period of time between drydockings, generally three to five years. This Staff Position requires that all periods presented in our consolidated financial statements reflect the period-specific adjustments of applying the new accounting principle. As a result of applying this change, we have restated our consolidated balance sheet at January 1, 2006 to reflect an increase to assets and stockholders’ equity of approximately $41.7 million and $66.5 million, respectively, and a decrease to liabilities of approximately $24.8 million. Additionally, we have restated our consolidated statements of income for the years ended December 31, 2006 and 2005 to reflect an increase in our operating income of approximately $4.2 million and $7.7 million, respectively. Also for the year ended December 31, 2006, we have restated our consolidated statements of income to reflect an increase in our provision for income taxes of approximately $16.0 million. The impact on basic and diluted earnings per share for the years ended December 31, 2006 and 2005 was $(0.05) and $0.04 per share, respectively.

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Goodwill

The following summarizes the changes in the carrying amount of goodwill:

	Offshore Oil and Gas Construction		Government Operations		Power Generation Systems		Total
	(In thousands)

Balance at December 31, 2005	$	-	$	12,926	$	-	$	12,926
Reconsolidation of B&W PGG		-		-		75,198		75,198
Translation		-		-		1,102		1,102
Balance at December 31, 2006		-		12,926		76,300		89,226
Acquisition of Marine Mechanical Corporation (Note 2)		-		39,005		-		39,005
Acquisition of Assets from Secunda International Limited (Note 2)		29,066		-		-		29,066
Translation		457		-		779		1,236
Balance at December 31, 2007	$	29,523	$	51,931	$	77,079	$	158,533

Other Intangible Assets

We report our other intangible assets in other assets. We amortize those intangible assets which have definite lives to operating expense, using the straight-line method.

During the year ended December 31, 2007, we acquired the following intangible assets subject to amortization (dollars in thousands; periods in years):

Intangible Asset Class	Amount		Weighted-Average Amortization Period

Customer Relationship	$	31,720		14
Backlog		9,540		5
Trade Name		1,770		5
	$	43,030		11

None of these acquired intangible assets have any residual value. See Note 2 for additional details on these acquired intangible assets.

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Other assets include the following other intangible assets:

	Year Ended December 31,
	2007			2006			2005
	(In thousands)
Amortized intangible assets:
Gross cost:
Customer relationships	$	31,927		$	-		$	-
Acquired backlog		9,540			-			-
Trade name		1,770			-			-
All other		7,737			9,886			959
Total	$	50,974		$	9,886		$	959

Accumulated amortization:
Customer relationships	$	(2,578	)	$	-		$	-
Acquired backlog		(1,363	)		-			-
Trade name		(236	)		-			-
All other		(3,994	)		(5,586	)		(959	)
Total	$	(8,171	)	$	(5,586	)	$	(959	)
Net amortized intangible assets	$	42,803		$	4,300		$	-

Unamortized intangible assets:
Trademarks	$	1,305		$	1,305		$	-

The following summarizes the changes in the carrying amount of other intangible assets:

	Year Ended December 31,
	2007			2006			2005
	(In thousands)

Balance at beginning of period	$	5,605		$	-		$	12
Reconsolidation of B&W PGG		-			6,071			-
Acquisition of Marine Mechanical Corporation		31,100			-			-
Acquisition of Secunda International Limited assets		11,930			-			-
Amortization expense		(4,735	)		(466	)		(12	)
Translation		208			-			-
Balance at end of period	$	44,108		$	5,605		$	-

The estimated amortization expense for the next five fiscal years are as follows:

Year Ended December 31,	Amount
2008	$	8,054
2009	$	6,377
2010	$	5,781
2011	$	4,828
2012	$	1,689

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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:

	Year Ended December 31,
	2007			2006			2005
	(In thousands)

Balance at beginning of period	$	19,798		$	11,614		$	13,977
Additions (1)		3,625			10,170			949
Reconsolidation of B&W PGG		-			9,873			-
Terminations and retirements		-			(7,865	)		-
Interest expense – debt issuance costs		(8,912	)		(3,994	)		(3,312	)
Balance at end of period	$	14,511		$	19,798		$	11,614
(1) For the year ended December 31, 2007, additions are deferred debt issuance costs related to amendments to the credit facilities of our Power Generation Systems segment ($2.1 million) and our Offshore Oil and Gas Construction segment ($1.5 million). For the year ended December 31, 2006, additions are deferred debt issuance costs related to our Offshore Oil and Gas segment and performance guarantees.

Capitalization of Interest Cost

We capitalize interest in accordance with SFAS No. 34, “Capitalization of Interest Cost.” We incurred total interest of $28.5 million, $33.4 million and $33.7 million in the years ended December 31, 2007, 2006 and 2005, respectively, of which we capitalized $6.0 million, $3.1 million and $1.9 million in the years ended December 31, 2007, 2006 and 2005, respectively.

Restricted Cash and Cash Equivalents

We record current cash and cash equivalents 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. Any 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.

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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 insurance (within certain limits) and marine hull to our companies. We may also, in the future, have these insurance subsidiaries accept other risks that we cannot 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 these coverages. These accruals are based on 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.

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 11. 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 various factors, including 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.

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,” to use the intrinsic value method described in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”), 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, performance shares and stock options, is determined on the date of grant and is not remeasured. Grant date fair values for restricted stock and performance shares are determined using the closing price of our common stock on the date of grant. Grant date fair values for stock options are determined using the Black-Scholes option-pricing model (“Black-Scholes”). 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 deferred stock units and performance units, fair values are determined at grant date using the closing price of our common stock 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 periodically and record any adjustments deemed necessary for each reporting period. If our actual

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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 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 Securities and Exchange Commission 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 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 10 for further discussion on stock-based compensation.

Stock options granted to employees of certain subsidiaries in our Power Generation Systems segment during the pendency of their Chapter 11 Bankruptcy proceedings were accounted for using the fair value method of SFAS No. 123, as these employees were not considered employees of MII for purposes of APB No. 25. In addition, for the year ended December 31, 2005, our stock-based compensation cost included amounts related to stock options that required variable accounting.

New Accounting Standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 became effective for our financial assets and liabilities on January 1, 2008. On February 12, 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157,” to provide a partial deferral of SFAS No. 157. The FSP defers the effective date of SFAS No. 157 for all nonfinancial assets and liabilities, excluding those recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. SFAS No. 157 is not expected to materially affect our determination of fair value but may result in additional disclosures.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies to choose to measure certain financial assets and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS No. 159 became effective for us on January 1, 2008. We do not plan to elect the fair value option for any of our existing financial instruments on the effective date and have not determined whether or not we will elect the option for any eligible financial instruments we acquire in the future.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51.” SFAS No. 160 establishes accounting and reporting standards pertaining to ownership interests in subsidiaries held by parties other than the parent, the amount of net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of any retained noncontrolling equity investment when a subsidiary is deconsolidated. It also establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 will be effective for us January 1, 2009. We are currently reviewing this new guidance to determine the impact on our consolidated financial condition, results of operations and related disclosures.

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In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141(R)”), which amends SFAS No. 141, “Business Combinations.” SFAS No. 141(R) broadens the guidance of SFAS No. 141, extending its applicability to all transactions and events in which one entity obtains control over one or more other businesses. It broadens the fair value measurements and recognition of assets acquired, liability assumed and interests transferred as a result of business combinations. It also provides disclosure requirements to enable users of the financial statements to evaluate the nature and financial effects of business combinations. SFAS No. 141(R) will be effective for us January 1, 2009. We do not expect the adoption of SFAS No. 141(R) to have a material effect on our consolidated financial statements. However, we are reviewing the effects SFAS No. 141(R) may have on future business combinations.

NOTE 2 – BUSINESS ACQUISITIONS

Acquisition of Marine Mechanical Corporation

On May 1, 2007, our Government Operations segment completed its stock acquisition of Marine Mechanical Corporation for approximately $72 million in cash. In addition, we recognized liabilities in excess of those directly assumed from Marine Mechanical Corporation of approximately $16 million, primarily related to deferred income taxes. We recorded goodwill of approximately $39 million in connection with this acquisition, none of which will be deductible for tax purposes. Headquartered in Euclid, Ohio, Marine Mechanical Corporation designs, manufactures and supplies electro-mechanical equipment used by the U.S. Navy. In addition to the goodwill, we recorded identifiable intangible assets of approximately $31 million, which have a weighted-average amortization period of 14.4 years. Those intangible assets consist of the following (amounts in thousands):

			Amortization
	Amount		Period
Customer Relationship	$	19,790	20.0 years
Backlog	$	9,540	4.7 years
Trade Name	$	1,770	5.0 years

Acquisition of Assets from Secunda International Limited

On July 27, 2007, our Offshore Oil and Gas Construction segment completed its acquisition of substantially all of the assets of Secunda International Limited, including 14 harsh-weather, multi-functional vessels, with capabilities which include subsea construction, pipelay, cable lay and dive support, as well as its shore-based operations, for approximately $263 million in cash and the assumption of approximately $10 million of liabilities, including approximately $4 million related to deferred income taxes. We recorded goodwill of approximately $29 million in connection with this acquisition, none of which will be deductible for tax purposes. In addition to the goodwill, we recorded identifiable intangible assets of approximately $12 million related to contractual customer relationships, which have a weighted-average amortization period of 3.6 years.

NOTE 3 –DISCONTINUED OPERATIONS

In April 2006, we completed the sale of our Mexican subsidiary, Talleres Navales del Golfo, S.A. de C.V. (“TNG”), previously a component of our Offshore Oil and Gas Construction segment. As a result of that 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 statement of income for the year ended December 31, 2006.

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In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the consolidated statement of income for the year ended December 31, 2005 has been restated for consistency to reflect TNG as a discontinued operation. Condensed financial information for our operations reported in discontinued operations is as follows:

	Year Ended December 31,
	2006			2005
	(In thousands)

Revenues	$	4,466		$	16,571
Income (Loss) before Provision for (Benefit from) Income Taxes	$	(802	)	$	686

NOTE 4 – EQUITY METHOD INVESTMENTS

We have investments in entities that we account for using the equity method. The undistributed earnings of our equity method investees were $33.5 million and $28.5 million at December 31, 2007 and 2006, 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:

	December 31,
	2007		2006
	(In thousands)

Current Assets	$	228,213	$	196,809
Noncurrent assets		117,400		116,640
Total Assets	$	345,613	$	313,449

Current Liabilities	$	121,244	$	120,313
Noncurrent Liabilities		82,418		73,065
Owners’ Equity		141,951		120,071
Total Liabilities and Owners’ Equity	$	345,613	$	313,449

	Year Ended December 31,
	2007		2006		2005
	(In thousands)

Revenues	$	1,889,273	$	1,829,688	$	1,831,573

Gross Profit	$	152,063	$	138,312	$	117,088

Income before Provision for Income Taxes	$	114,551	$	101,743	$	90,812
Provision for Income Taxes		15,916		10,732		4,642
Net Income	$	98,635	$	91,011	$	86,170

Revenues of equity method investees include $1,392.7 million, $1,403.4 million and $1,660.5 million of reimbursable costs recorded by limited liability companies in our Government Operations segment at December 31, 2007, 2006 and 2005, 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 $1.4 million at December 31, 2007. These differences were primarily related to the timing of distribution of dividends and various adjustments under U.S. GAAP.

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

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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:

	Year Ended December 31,
	2007			2006			2005
	(In thousands)
Equity income based on stated ownership percentages	$	46,966		$	42,366		$	40,722
Sale of shares in foreign entity		-			-			3,073
Impairment of investment		-			(2,609	)		-
All other adjustments due to amortization of basis differences, timing of GAAP adjustments, dividend distributions and other adjustments		(5,242	)		(2,233	)		(3,272	)
Equity in income from investees	$	41,724		$	37,524		$	40,523

Our transactions with unconsolidated affiliates include the following:

	Year Ended December 31,
	2007		2006		2005
	(In thousands)
Sales to	$	9,750	$	48,407	$	81,311
Purchases from	$	42,686	$	31,602	$	-
Leasing activities (included in sales to)	$	-	$	36,020	$	74,170
Dividends received	$	41,844	$	39,072	$	35,809

During the year ended December 31, 2005, we leased certain marine equipment to an unconsolidated affiliate. During the year ended December 31, 2006, we disposed of our interest in that unconsolidated affiliate. As discussed further in Note 13, during the year ended December 31, 2004, we sold the vessel DB17 to that unconsolidated affiliate. However, we deferred recognition of the gain on that sale until the receivables were settled. Such settlement occurred during the year ended December 31, 2007, and we recognized the gain on sale of approximately $5.4 million.

Effective January 1, 2006, we converted the accounting for our investment in Babcock & Wilcox Beijing Company, Ltd., a Chinese entity, 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 at January 1, 2006. For the years ended December 31, 2007 and 2006, we recognized $10.3 million and $8.3 million, respectively, of equity income related to this entity.

NOTE 5 - INCOME TAXES

We provide 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 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 basis on which these rates are applied. These variances, along with variances in our mix of income from these jurisdictions, contribute to shifts in our effective tax rate.

On December 31, 2006, we completed a reorganization of our U.S. tax groups into a single consolidated U.S. tax group. 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. Beginning January 1, 2007, the results of the former separate U.S. tax groups are consolidated.

We conduct business globally, and as a result, we or one or more of our subsidiaries file income tax returns in the U.S. federal jurisdiction and in many state and foreign jurisdictions. In the normal course of business, we are subject to examination by taxing authorities throughout the world, including such major jurisdictions as Canada,

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Indonesia, Malaysia, China, Singapore, Saudi Arabia, Kuwait, India, Qatar, Azerbaijan and the United States. With few exceptions, we are no longer subject to non-U.S. tax examinations for years prior to 2000.

Both of our former U.S. tax groups are currently under audit by the Internal Revenue Service (the “IRS”). The IRS examination of the years 1993 through 2003 for one group has been completed. We are awaiting final resolution of all disputed adjustments from an appellate conference with the IRS and a subsequent review by the Joint Committee on Taxation. Additionally, the IRS has commenced the examination for the years 2004 through 2006 for this group. The IRS examination of the years 1996 through 2003 for the other group is also complete and is pending review by the Joint Committee on Taxation. It is anticipated that a settlement with the IRS for all years under audit may be reached within the next 12 months.

State income tax returns are generally subject to examination for a period of three to five years after filing the respective returns. With few exceptions, we do not have any state returns under examination for years prior to 2000.

Effective January 1, 2007, we adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). As a result of this adoption, we recognized a charge of approximately $12.0 million to our accumulated deficit component of stockholders’ equity. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (amounts in millions):

Balance at January 1, 2007	$	70,433

Increases based on tax positions taken in the current year		2,217
Increases based on tax positions taken in the prior years		7,742
Decreases based on tax positions taken in the prior years		(12,759	)
Decreases due to settlements with tax authorities		(2,313	)
Decreases due to lapse of applicable statute of limitations		(510	)

Balance at December 31, 2007	$	64,810

Approximately $63.4 million of the balance of unrecognized tax benefits at December 31, 2007 would reduce our effective tax rate if recognized. The remaining balance relates to positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

As part of the adoption of FIN 48, we began to recognize interest and penalties related to unrecognized tax benefits in income tax expense. As of the date of implementation, we recorded liabilities of approximately $27.3 million for the payment of tax-related interest and penalties, including amounts recorded upon implementation. At December 31, 2007, we have recorded liabilities of approximately $20.4 million for the payment of tax-related interest and penalties. The $6.9 million change during the year is attributable to the reassessment of certain tax positions from the U.S. federal audits described above, as well as payment of interest to the state of Virginia from a prior audit settlement.

It is reasonably possible that within the next 12 months we will see a decrease of approximately $22.6 million in unrecognized tax benefits and a related $8.7 million of interest and penalties as a result of settling various federal, state and international audits.

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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, 2007 and 2006 were as follows:

	December 31,
	2007			2006
	(In thousands)

Deferred tax assets:
Pension liability	$	93,393		$	151,709
Minimum tax credit carryforward		26,536			5,576
Accrued warranty expense		36,318			26,690
Accrued vacation pay		11,209			10,101
Accrued liabilities for self-insurance (including postretirement health care benefits)		52,057			51,710
Accrued liabilities for executive and employee incentive compensation		62,733			49,155
Investments in joint ventures and affiliated companies		1,667			2,151
Net operating loss carryforward		20,007			122,563
Environmental and products liabilities		29,068			27,982
Long-term contracts		16,459			30,015
Accrued interest		1,602			770
State tax net operating loss carryforward		67,473			109,772
Capital loss carryforward		-			3,419
Foreign tax credit carryforward		18,583			18,670
Other		15,290			17,556
Total deferred tax assets		452,395			627,839
Valuation allowance for deferred tax assets		(100,617	)		(152,950	)
Deferred tax assets		351,778			474,889
Deferred tax liabilities:
Property, plant and equipment		27,430			30,336
Prepaid drydock		9,832			11,113
Investments in joint ventures and affiliated companies		7,883			7,896
Intangibles		15,183			-
Other		7,146			6,527
Total deferred tax liabilities		67,474			55,872
Net deferred tax assets	$	284,304		$	419,017

Income from continuing operations before provision for income taxes was as follows:

	Year Ended December 31,
	2007		2006		2005
	(In thousands)

U.S.	$	266,984	$	89,910	$	56,750
Other than U.S.		478,481		262,906		157,660
Income from continuing operations before provision for income taxes	$	745,465	$	352,816	$	214,410

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The provision for income taxes consisted of:

	Year Ended December 31,
	2007			2006			2005
	(In thousands)
Current:
U.S. – Federal	$	(16,872	)	$	(207,675	)	$	28,727
U.S. – State and local		6,621			12,829			2,863
Other than U.S.		58,264			50,574			24,794
Total current		48,013			(144,272	)		56,384
Deferred:
U.S. - Federal		93,815			186,721			(47,685	)
U.S. – State and local		687			(321	)		128
Other than U.S.		(4,878	)		(6,933	)		-
Total deferred		89,624			179,467			(47,557	)
Provision for income taxes	$	137,637		$	35,195		$	8,827

The following is a reconciliation of the U.S. statutory federal tax rate (35%) to the consolidated effective tax rate:

	Year Ended December 31,
	2007			2006			2005
	(In thousands)
U.S. federal statutory (benefit) rate		35.0	%		35.0	%		35.0	%
State and local income taxes		0.8			2.1			2.0
Non-U.S. operations		(13.7	)		(9.4	)		(14.2	)
Non-deductible Chapter 11 Bankruptcy expense		-			-			1.6
Expiration of foreign tax credits		-			3.0			-
Valuation allowance for deferred tax assets		(2.0	)		(22.8	)		(21.3	)
Other		(1.6	)		2.1			1.0
Effective tax rate attributable to continuing operations		18.5	%		10.0	%		4.1	%

For the year ended December 31, 2005, we recorded a tax provision benefit of $50.4 million from the reversal of the valuation allowance related to our minimum pension liability. For the year ended December 31, 2006, we reduced the valuation allowance $78.1 million on various deferred assets and recorded a benefit to the provision as a result of the reorganization of our U.S. legal entities.

At December 31, 2007, we had a valuation allowance of $100.6 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 $55.6 million available to offset future taxable income in foreign jurisdictions. Approximately $16.4 million of the foreign net operating loss carryforwards is scheduled to expire in 2008 to 2010. The foreign net operating losses have a valuation allowance of $11.4 million against them. We have domestic net operating loss carryforwards of approximately $121.7 million available to offset future taxable income in domestic jurisdictions, including $115.4 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 $1,087.3 million available to offset future taxable income in various states. The state net operating loss carryforwards begin to expire in the year 2008. The state net operating losses have a valuation allowance against the entire carryforward.

We would be subject to withholding taxes if we were to distribute earnings from our U.S. subsidiaries and certain foreign subsidiaries. For the year ended December 31, 2007, the undistributed earnings of these subsidiaries were $589.4 million. Unrecognized deferred income tax liabilities, including withholding taxes, of approximately

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$172.9 million would be payable upon distribution of these earnings. We have provided $3.1 million of taxes on earnings we intend to remit. All other earnings are considered permanently reinvested.

NOTE 6 - LONG-TERM DEBT AND NOTES PAYABLE

	December 31,
	2007		2006
	(In thousands)

Long-term debt consists of:
Unsecured Debt:
Other notes payable through 2009 (interest at various rates up to 6.8%)	$	14,824	$	19,283
Secured Debt:
Power Generation Systems – various notes payable		2,384		2,455
Power Generation Systems – term loan due 2012 ($250,000 principal amount)		-		250,000
		17,208		271,738
Less: Amounts due within one year		6,599		256,496
Long-term debt	$	10,609	$	15,242
Notes payable and current maturities of long-term debt consist of:
Short-term lines of credit	$	-	$	996
Current maturities of long-term debt		6,599		256,496
Total	$	6,599	$	257,492
Weighted average interest rate on short-term borrowing		-		6.70	%

Maturities of long-term debt during the five years subsequent to December 31, 2007 are as follows: 2008 – $6.6 million; 2009 – $4.6 million; 2010 – $0.4 million; 2011 – $0.4 million; and 2012 – $4.4 million.

Offshore Oil and Gas Construction

On June 6, 2006, one of our subsidiaries, J. Ray McDermott, S.A. entered into a senior secured credit facility with a syndicate of lenders (the “JRMSA Credit Facility”). During July 2007, the JRMSA Credit Facility was amended to, among other things, (1) increase the revolving credit facility by $100 million to $500 million and eliminate a synthetic letter of credit facility, (2) reduce the commitment fees and applicable margins for revolving loans and letters of credit and (3) eliminate the limitation on revolving credit borrowings. The JRMSA Credit Facility now consists of a five-year, $500 million revolving credit facility (under which all of the credit capacity may be used for the issuance of letters of credit and revolver borrowings), which matures on June 6, 2011. The proceeds of the JRMSA Credit Facility are available for working capital needs and other general corporate purposes of our Offshore Oil and Gas Construction segment.

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The JRMSA 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. At December 31, 2007, JRMSA was in compliance with all of the covenants set forth in the JRMSA Credit Facility.

On December 22, 2005, JRMSA, 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 $172.8 million outstanding referenced above. This facility provides credit support for bank guarantees issued in connection with three major projects. The term of this facility is for the duration of these projects, and the average commission rate is less than 4.5% on an annualized basis.

On June 6, 2006, JRMSA completed a cash tender offer for all its outstanding 11% senior secured notes due 2013 (the “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. JRMSA used cash on hand to purchase the entire $200 million in aggregate principal amount of the 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.

Government Operations

The BWXT Credit Facility requires BWXT to comply with various financial and nonfinancial covenants and reporting requirements. The financial covenants require maintenance of a maximum leverage ratio, a minimum fixed charge coverage ratio and a maximum debt to capitalization ratio within our Government Operations segment. At December 31, 2007, BWXT was in compliance with all of the covenants set forth in the BWXT Credit Facility.

At December 31, 2007, there were no borrowings outstanding, and letters of credit issued under the BWXT Credit Facility totaled $48.0 million. At December 31, 2007, there was $87.0 million available for borrowings or to meet letter of credit requirements under the BWXT Credit Facility.

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Power Generation Systems

The B&W PGG Credit Facility only requires interest payments on a quarterly basis until maturity. Amounts outstanding under the B&W PGG Credit Facility may be prepaid at any time without penalty.

The B&W PGG Credit Facility contains customary financial covenants within our Power Generation Systems segment, including maintenance of a maximum leverage ratio and a minimum interest coverage ratio, and covenants that, among other things, restrict the ability of this segment 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 PGG Credit Facility also contains customary events of default. At December 31, 2007, B&W PGG was in compliance with all of the covenants set forth in the B&W PGG Credit Facility.

Other

Certain of our subsidiaries are restricted in their ability to transfer funds to MII. Such restrictions principally arise from debt covenants, insurance regulations, national currency controls and the existence of minority shareholders. We refer to the proportionate share of net assets, after intercompany eliminations, that may not be transferred to MII as a result of these restrictions, as “restricted net assets.” At December 31, 2007, the restricted net assets of our consolidated subsidiaries were approximately $596 million.

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NOTE 7 - PENSION PLANS AND POSTRETIREMENT BENEFITS

We have historically provided defined benefit retirement benefits, primarily through noncontributory pension plans, for most of our regular employees. Effective March 31, 2003, the retirement plan for U.S.-based employees of our Offshore Oil and Gas Construction segment was closed to new entrants and benefit accruals were frozen for existing participants. Effective March 31, 2006, the retirement plans for corporate employees and for U.S.-based salaried employees of our Government Operations and Power Generation Systems segments were closed to new entrants, and benefit accruals were frozen for existing salaried participants hired on or after April 1, 2001. Effective December 31, 2007, the salaried retirement plan acquired with Marine Mechanical Corporation in May, 2007 was closed to new entrants and benefit accruals were frozen for existing participants who were not vested as of December 31, 2007. In addition, we do not provide retirement benefits to certain non-resident alien employees of foreign subsidiaries. Retirement benefits for salaried employees who accrue benefits in a defined benefit plan are based on final average compensation and years of service, while benefits for hourly paid employees are based on a flat benefit rate and years of service. Our funding policy is to fund the plans as recommended by the respective plan actuaries and in accordance with the Employee Retirement Income Security Act of 1974, as amended, or other applicable law. The Pension Protection Act of 2006 replaces the current funding provisions for single-employer defined benefit plans. Funding provisions under the Pension Protection Act accelerate funding requirements to ensure full funding of benefits accrued. The Pension Protection Act became effective in 2008, and we do not anticipate any material impact on our consolidated financial condition or cash flows.

Effective December 31, 2007, we adopted the measurement date provision of SFAS No. 158, “Employers Accounting for Defined Benefit Pension and Other Postretirement Plans,” for our plans that were not on a calendar year measurement. In accordance with this provision, we recorded a reduction in retained earnings of $1.7 million, net of a related tax benefit of $0.8 million.

Effective December 31, 2006, we adopted the recognition and disclosure provisions of 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 was 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 were reversed.

In December 2005, we recorded an additional gain totaling $1.4 million related to the finalization of the 2004 termination of one of our pension plans in the United Kingdom.

We make available other benefits which include postretirement health care and life insurance benefits to certain salaried and union retirees based on their union contracts. Certain subsidiaries provide these benefits to unionized and salaried future retirees.

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Obligations and Funded Status

	Pension Benefits Year Ended December 31,						Other Benefits Year Ended December 31,
	2007			2006			2007			2006
	(In thousands)

Change in benefit obligation:
Benefit obligation at beginning of period	$	2,521,895		$	2,313,191		$	108,697		$	38,999
Service cost		37,766			37,724			331			129
Interest cost		149,329			133,176			5,993			5,269
Measurement date change		4,203			-			189			-
Acquisition of Marine Mechanical Corporation		24,830			-			1,681			-
Plan participants’ contributions		319			315			-			-
Reconsolidation of B&W PGG		-			197,750			-			66,251
Amendments		(26,381	)		(496	)		-			-
Medicare reimbursement		-			-			19			-
Actuarial (gain) loss		10,197			(26,669	)		(2,530	)		8,786
Foreign currency exchange rate changes		28,436			4,728			1,332			(60	)
Benefits paid		(144,877	)		(137,824	)		(12,142	)		(10,677	)
Benefit obligation at end of period		2,605,717		$	2,521,895		$	103,570		$	108,697

Change in plan assets:
Fair value of plan assets at beginning of period	$	2,050,215		$	1,706,343		$	-		$	-
Actual return on plan assets		191,203			217,798			-			-
Measurement date change		3,027			-			-			-
Acquisition of Marine Mechanical Corporation		16,466			-			-			-
Plan participants’ contributions		319			315			-			-
Company contributions		138,630			104,668			12,142			10,676
Reconsolidation of B&W PGG		-			155,190			-			-
Foreign currency exchange rate changes		25,001			3,725			-			-
Benefits paid		(144,877	)		(137,824	)		(12,142	)		(10,676	)
Fair value of plan assets at the end of period		2,279,984			2,050,215			-			-
Funded status	$	(325,733	)	$	(471,680	)	$	(103,570	)	$	(108,697	)

Amounts recognized in the balance sheet consist of:
Prior to Adoption of SFAS No. 158
Accrued employee benefits		N/A		$	(104,073	)		N/A		$	(8,381	)
Accumulated postretirement benefit obligation		N/A			-			N/A			(79,716	)
Pension liability		N/A			(242,734	)		N/A			-
Intangible asset		N/A			24,539			N/A			-
Accumulated other comprehensive loss		N/A			318,213			N/A			-
Net amount recognized		N/A		$	(4,055	)		N/A		$	(88,097	)

After Adoption of SFAS No. 158
Accrued employee benefits	$	(159,601	)	$	(104,073	)	$	(7,317	)	$	(8,381	)
Accumulated postretirement benefit obligation		-			-			(96,253	)		(100,316	)
Pension liability		(182,739	)		(367,607	)		-			-
Prepaid pension		16,607			-			-			-
Accrued benefit liability, net	$	(325,733	)	$	(471,680	)	$	(103,570	)	$	(108,697	)

Amounts recognized in accumulated other comprehensive loss:
Net actuarial loss	$	367,057		$	450,352		$	14,413		$	18,494
Prior service cost		17,401			17,273			473			578
Unrecognized transition obligation		-			-			1,156			1,528
Total before taxes	$	384,458		$	467,625		$	16,042		$	20,600

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The projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $2,364.4 million, $2,266.2 million and $2,046.1 million, respectively, at December 31, 2007 for plans with accumulated benefit obligation in excess of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets were $241.3 million, $218.4 million and $233.9 million, respectively, at December 31, 2007 for plans with plan assets in excess of the accumulated benefit obligation. 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. The accumulated benefit obligation was in excess of plan assets for all of our plans at December 31, 2006.

	Pension Benefits Year Ended December 31,									Other Benefits Year Ended December 31,
	2007(1)			2006			2005(2)			2007(1)		2006		2005

Components of net periodic benefit cost:
Service cost	$	37,766		$	37,724		$	28,931		$	331	$	129	$	-
Interest cost		149,329			133,176			121,981			5,993		5,269		2,166
Expected return on plan assets		(172,087	)		(143,674	)		(134,400	)		-		-		-
Amortization of transition obligation		-			-			-			273		222		-
Amortization of prior service cost		3,091			3,142			3,110			71		58		-
Recognized net actuarial loss		45,799			63,183			43,068			1,723		1,402		1,489
Net periodic benefit cost	$	63,898		$	93,551		$	62,690		$	8,391	$	7,080	$	3,655
(1) Excludes approximately $2.2 million and $0.3 million of net benefit cost for pension benefits and other benefits, respectively, which have been recorded as adjustments to beginning-of-year retained earnings. (2) Includes approximately $35 million of expense which was recorded in our Power Generation Systems segment attributable to the spin-off of the B&W PGG pension plan from MI.

Additional Information

	Pension Benefits Year Ended December 31,					Other Benefits Year Ended December 31,
	2007		2006			2007		2006
	(In thousands)
Decrease in accumulated other comprehensive loss due to actuarial gains (before taxes)	$	34,625		N/A		$	2,487		N/A

Increase in accumulated other comprehensive loss due to adoption of SFAS No. 158 (before taxes)		N/A	$	124,873			N/A	$	20,600

Decrease in minimum liability included in other comprehensive income (before taxes)		N/A	$	(85,001	)		N/A		N/A

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 PGG.

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We have recognized in the current fiscal year, and expect to recognize in the next fiscal year, the following amounts in other comprehensive loss as components of net periodic benefit cost:

	Recognized in the Year Ended December 31, 2007				To Be Recognized in the Year Ended December 31, 2008
	Pension		Other		Pension		Other
	(In thousands)
Pension cost in accumulated other comprehensive loss:
Net actuarial loss	$	45,799	$	1,723	$	34,765	$	1,470
Prior service cost		3,091		71		3,074		76
Transition obligation		-		273		-		294
	$	48,890	$	2,067	$	37,839	$	1,840

Assumptions

	Pension Benefits						Other Benefits
	2007			2006			2007			2006

Weighted average assumptions used to determine net periodic benefit obligations at December 31:
Discount rate		6.14	%		5.92	%		5.74	%		5.75	%
Rate of compensation increase		3.96	%		3.96	%		-			-
Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31:
Discount rate		5.89	%		5.67	%		5.70	%		5.75	%
Expected return on plan assets		8.33	%		8.28	%		-			-
Rate of compensation increase		3.93	%		3.96	%		-			-

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.

	2007(1)			2006

Assumed health-care cost trend rates at December 31
Health-care cost trend rate assumed for next year		8.00% - 9.00	%		9.00	%
Rates to which the cost trend rate is assumed to decline (ultimate trend rate)		4.50	%		4.50	%
Year that the rate reaches ultimate trend rate		2012 - 2013		2012

(1) Assumed health-care cost trend rate for our existing plans is 8.00%, reaching the ultimate trend rate in 2012. The assumed health-care cost trend rate for our plans acquired with Marine Mechanical Corporation is 9.00%, reaching the ultimate trend rate in 2013.

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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:

	One-Percentage- Point Increase		One-Percentage- Point Decrease
	(In thousands)
Effect on total of service and interest cost	$	335	$	(303	)
Effect on postretirement benefit obligation	$	5,076	$	(4,619	)

Investment Goals

General

The overall investment strategy of the pension trusts is to achieve 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.

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

We sponsor the following domestic defined benefit plans:

·	Retirement Plan for Employees of McDermott Incorporated and Participating Subsidiary and Affiliated Companies (covering corporate employees);

·	Retirement Plan for Employees of J. Ray McDermott Holdings, LLC and Participating Subsidiary and Affiliated Companies (the “J. Ray Plan,” covering Offshore Oil and Gas Construction segment employees);

·	Retirement Plan for Employees of The Babcock & Wilcox Company and Participating Subsidiary and Affiliated Companies (covering Power Generation Systems segment employees);

·	Retirement Plan for Employees of BWX Technologies, Inc. (covering Government Operations segment employees); and

·	Marine Mechanical Corporation Hourly Pension Plan and Marine Mechanical Corporation Salaried pension Plan (collectively, the “MMC Plans”) acquired with Marine Mechanical Corporation.

For the years ended December 31, 2007 and 2006, the investment return on domestic plan assets (before deductions for management fees) was approximately 10.2% and 12.4%, 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”). Our domestic pension plans’ asset allocations at December 31, 2007 and 2006 by asset category were as follows:

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	2007			2006
Asset Category:
Equity Securities		34	%		42	%
Debt Securities		33	%		28	%
Partnerships with Security Holdings		12	%		10	%
U.S. Government Securities		10	%		8	%
Real Estate		8	%		5	%
Other		3	%		7	%
Total		100	%		100	%

The target allocation for 2008 for the domestic plans, by asset class, is as follows:

	JRAY Plan			MMC Plans			Other Plans
Asset Class:
Public Equity		-	%		70.0	%		42.5	%
Private Equity		-	%		-	%		10.0	%
Fixed Income		98.0	%		29.0	%		38.0	%
Real Estate		-	%		-	%		5.0	%
Other		2.0	%		1.0	%		4.5	%

Foreign Plans

We sponsor various plans through certain of our foreign subsidiaries. These plans are the J. Ray McDermott, S.A. TCN Employees Pension Plan (the “TCN Plan”), various plans of Babcock & Wilcox Canada, Ltd. (the “Canadian Plans”) and the Diamond Power Specialty Limited Retirement Benefits Plan (the “Diamond UK Plan”).

The weighted average asset allocations of these plans at December 31, 2007 and 2006 by asset category were as follows:

	2007			2006
Asset Category:
Equity Securities		62	%		65	%
Debt Securities		35	%		30	%
Other		3	%		5	%
Total	$	100	%		100	%

The target allocation for 2008 for the foreign plans, by asset class, is as follows:

	TCN Plan			Canadian Plans			Diamond UK Plan
Asset Class:
U. S. Equity		40	%		20	%		10	%
Global Equity		30	%		40	%		50	%
Fixed Income		30	%		40	%		40	%

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Cash Flows

	Domestic Plans				Foreign Plans
	Pension Benefits		Other Benefits		Pension Benefits		Other Benefits

Expected employer contributions to trusts of defined benefit plans:
2008	$	134,503		N/A	$	21,594		N/A
Expected benefit payments:
2008	$	140,155	$	12,470	$	13,158	$	549
2009	$	146,988	$	12,226	$	12,909	$	590
2010	$	153,922	$	11,844	$	13,662	$	640
2011	$	160,261	$	11,424	$	15,290	$	691
2012	$	167,584	$	10,698	$	15,553	$	743
2013-2017	$	918,460	$	42,042	$	97,817	$	4,479

The expected employer contributions to trusts for 2008 are included in current liabilities at December 31, 2007. We are currently reviewing funding alternatives for certain domestic pension plans. It is possible that amounts actually contributed to these plans in 2008 will exceed the amounts included in current liabilities at December 31, 2007.

Defined Contribution Plans

We provide benefits under the McDermott International, Inc. Supplemental Executive Retirement Plan (“SERP Plan”), which is a defined contribution plan. We recorded expenses related to the SERP Plan of approximately $1.1 million, $2.9 million and $1.3 million in the years ended December 31, 2007, 2006 and 2005, respectively.

We also provide benefits under the Thrift Plan for Employees of McDermott Incorporated and Participating Subsidiary and Affiliated Companies (“Thrift Plan”). The Thrift Plan generally provides for matching employer contributions of 50% of participants’ contributions up to 6 percent of compensation. These matching employer contributions are typically made in shares of MII common stock. The Thrift Plan also provides for unmatched employer cash contributions to certain employees of our Offshore Oil and Gas Construction segment as well as service-based contributions to salaried corporate employees and salaried employees within our Power Generation Systems and Government Operations segments. Amounts charged to expense for employer contributions under the Thrift Plan totaled approximately $18.6 million, $14.6 million and $8.2 million in the years ended December 31, 2007, 2006 and 2005, respectively.

Multiemployer Plans

One of the subsidiaries in our Power Generation Systems segment contributes to various multiemployer plans. The plans generally provide defined benefits to substantially all unionized workers in this subsidiary. Amounts charged to pension cost and contributed to the plans were $32.6 million in the year ended December 31, 2007 and $24.4 million in the period ended December 31, 2006, since the reconsolidation of B&W PGG and its subsidiaries as of February 22, 2006.

NOTE 8 – 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 an entity operating in Mexico, offset by gains on sales of various non-strategic assets, primarily in our Government Operations segment.

During the years ended December 31, 2007, 2006 and 2005, we did not record any impairments of property, plant and equipment.

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NOTE 9 - 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. 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, 2007 and 2006, 13,829,901 and 14,999,026 shares of common stock, respectively, were reserved for issuance in connection with those plans.

Increase in Authorized Shares

On May 4, 2007, our shareholders approved an amendment to our articles of incorporation increasing the number of authorized shares of common stock from 150 million to 400 million. The amendment became effective on August 6, 2007 upon filing of a certificate of amendment in the Public Registry Office of the Republic of Panama.

Stock Split

On August 7, 2007, our Board of Directors declared a two-for-one stock split effected in the form of a stock dividend. The dividend was paid on September 10, 2007 to stockholders of record as of the close of business on August 20, 2007. 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 these stock splits.

NOTE 10 – STOCK PLANS

At December 31, 2007, we had a stock-based employee compensation plan, which is described below. Where required, disclosures have been adjusted for our stock splits effected in the form of a stock dividend in September 2007 and May 2006. See Note 9 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 plan that have not been awarded, or that were subject to awards under this and other plans that have been canceled, terminated, forfeited, expired, settled in cash, or exchanged for consideration not involving shares, up to 7,500,000 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.

At December 31, 2007, we had a total of 7,397,650 shares of our common stock available for award under the 2001 Directors and Officers Long-Term Incentive Plan.

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1997 Director Stock Program

During 2007, we also maintained a 1997 Director Stock Program. Under this program, nonmanagement directors were entitled to receive a grant of options to purchase 2,700 shares of our common stock in the first year of a director's term and a grant of options to purchase 900 shares in subsequent years of such term at a purchase price equal to the fair market value of one share of our common stock on the date of grant. These options become exercisable, in full, six months after the date of grant and expire ten years from the date of grant. In addition, nonmanagement directors are entitled to receive a grant 1,350 shares of restricted stock in the first year of a director's term and 450 shares in subsequent years of such term. The shares of restricted stock are subject to payment by the director of a purchase price at par value ($1.00 per share) and to transfer restrictions that lapse at the end of the director's term. By the terms of the 1997 Director Stock Program, no award may be granted under the program beginning June 6, 2007. As a result, we made our final grants of stock options and restricted stock under the 1997 Directors Stock Program in connection with our Annual Meeting of Stockholders in May 2007. The shares of common stock available to be awarded under the 1997 Director Stock Program are available under the terms of the 2001 Directors and Officers Long-Term Incentive Plan and have been included in the amount available for grant discussed above.

In the event of a change in control of our company, all of 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 $2.7 and $4.4 million related to employee stock options during the years ended December 31, 2007 and 2006, respectively. During the year ended December 31, 2005, 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 year ended December 31, 2005 (in thousands, except per share data):

Net income, as reported	$	205,687
Add back: stock-based compensation cost included in net income, net of related tax effects		12,763
Deduct: total stock-based compensation cost determined under fair-value-based method, net of related tax effects		(10,894	)
Pro forma net income	$	207,556
Earnings per share:
Basic, as reported	$	1.00
Basic, pro forma	$	1.01
Diluted, as reported	$	0.94
Diluted, pro forma	$	0.95

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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, 2007, 2006 and 2005 was as follows:

	Compensation Expense		Tax Benefit			Net Impact
	(In thousands)
	Year Ended December 31, 2007
Stock options	$	2,740	$	(747	)	$	1,993
Restricted stock		904		(21	)		883
Performance shares		19,196		(6,085	)		13,111
Performance and deferred stock units		7,165		(2,314	)		4,851
TOTAL	$	30,005	$	(9,167	)	$	20,838

	Year Ended December 31, 2006
Stock options	$	4,352	$	(971	)	$	3,381
Restricted stock		1,199		(122	)		1,077
Performance shares		4,826		(1,329	)		3,497
Performance and deferred stock units		8,434		(2,195	)		6,239
TOTAL	$	18,811	$	(4,617	)	$	14,194

	Year Ended December 31, 2005
Repriced stock options	$	6,116	$	(1,128	)	$	4,988
Restricted stock		1,106		(251	)		855
Performance and deferred stock units		11,141		(2,899	)		8,242
TOTAL	$	18,363	$	(4,278	)	$	14,085

The impact on basic earnings per share of stock-based compensation expense recognized for the years ended December 31, 2007, 2006 and 2005 was $0.09, $0.07 and $0.07 per share, respectively, and on diluted earnings per share was $0.09, $0.06 and $0.06 per share, respectively.

As of December 31, 2007, total unrecognized estimated compensation expense related to nonvested awards was $39.3 million, net of estimated tax benefits of $18.3 million. The components of the total gross unrecognized estimated compensation expense of $57.6 million and their expected weighted-average periods for expense recognition are as follows (amounts in millions; periods in years):

	Amount		Weighted-Average Period
Stock options	$	0.9		0.4
Restricted stock	$	0.2		1.4
Performance shares	$	39.2		1.9
Performance and deferred stock units	$	17.3		2.4

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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:

	Year Ended December 31,
	2007			2006			2005
Risk-free interest rate		4.51	%		4.99	%		3.90	%
Expected volatility		0.50			0.50			0.71
Expected life of the option in years		5.28			4.94			5.70
Expected dividend yield		0.0	%		0.0	%		0.0	%

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, 2007 (share data in thousands):

	Number of Shares			Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value (in millions)
Outstanding, beginning of year		7,058		$	4.33
Granted		15			28.87
Exercised		(3,921	)		3.88
Cancelled/expired/forfeited		(23	)		6.94
Outstanding, end of year		3,129		$	4.99	5.12 Years	$	170.5
Exercisable, end of year		2,636		$	4.65	4.69 Years	$	144.5

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, 2007. 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, 2007, 2006 and 2005 was $14.48, $10.32 and $4.37, respectively. The total fair value of shares vested during the years ended December 31, 2007, 2006 and 2005 was $4.3 million, $5.0 million and $6.7 million, respectively.

During the years ended December 31, 2007, 2006 and 2005, the total intrinsic value of stock options exercised was $134.9 million, $102.4 million and $71.0 million, respectively. We recorded cash received in the years ended December 31, 2007, 2006 and 2005 from the exercise of these stock options totaling $15.2 million, $21.5 million and $53.0 million, respectively. The actual tax benefits realized related to the stock options exercised during the years ended 2006 and 2005 was $17.9 million and $14.2 million, respectively. Tax benefits related to the year ended December 31, 2007 have been deferred until utilization of the net operating losses causes the benefits to be realized. Additionally, tax benefits previously realized in prior years have also been deferred for a total deferral of $115.4 million, as discussed further in Note 5.

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Restricted Stock

Nonvested restricted stock awards as of December 31, 2007 and changes during the year ended December 31, 2007 were as follows (share data in thousands):

	Number of Shares			Weighted-Average Grant Date Fair Value
Nonvested, beginning of year		1,424		$	3.39
Granted		29			32.35
Vested		(1,076	)		4.69
Cancelled/forfeited		-			-
Nonvested, end of year		377		$	1.87

Performance Shares

Nonvested performance share awards as of December 31, 2007 and changes during the year ended December 31, 2007 were as follows (share data in thousands):

	Number of Shares			Weighted-Average Grant Date Fair Value
Nonvested, beginning of year		960		$	23.38
Granted		891			35.04
Vested		-			-
Cancelled/forfeited		(83	)		24.11
Nonvested, end of year		1,768		$	29.22

The actual number of shares earned by each participant is dependent upon achievement of certain consolidated operating income targets over the three-year performance periods. The awards actually earned will range from zero to 150% of the targeted number of performance shares, to be determined upon completion of the three-year performance period.

No performance shares vested during the years ended December 31, 2007, 2006 and 2005.

Performance and Deferred Stock Units

Nonvested performance and deferred stock unit awards as of December 31, 2007 and changes during the year ended December 31, 2007 were as follows (share data in thousands):

	Number of Units			Aggregate Intrinsic Value (in millions)
Nonvested, beginning of year		520
Granted		1
Vested		(134	)
Cancelled/forfeited		(13	)
Nonvested, end of year		374		$22.2

The aggregate intrinsic value included in the table above represents the total pretax intrinsic value recorded as a liability at December 31, 2007 in the consolidated balance sheets. During the years ended December 31, 2007 and

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2006, we paid $4.7 million and $26.2 million, respectively, for the settlement of vested performance and deferred stock units. There were no such settlements during the year ended December 31, 2005.

Thrift Plan

On November 12, 1991, 15,000,000 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 15,000,000 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, 2007, 2006 and 2005, we issued 333,939, 473,860 and 731,544 shares, respectively, of MII's common stock as employer contributions pursuant to the Thrift Plan. At December 31, 2007, 6,432,251 shares of MII's common stock remained available for issuance under the Thrift Plan.

NOTE 11 - CONTINGENCIES AND COMMITMENTS

Investigations and Litigation

Apollo/Parks Township Claims — Hall Litigation

On June 7, 1994, Donald F. Hall, Mary Ann Hall and others filed suit against B&W PGG, Babcock & Wilcox Technical Services Group, Inc., formerly known as B&W Nuclear Environmental Services, Inc., and Atlantic Richfield Company (“ARCO”) in the United States District Court for the Western District of Pennsylvania (the “Pennsylvania District Court”). 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”), previously owned by Nuclear Materials and Equipment Company (“Numec.”). 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 alleged radioactive and non-radioactive emissions from these facilities.

At the time of ARCO’s sale of Numec (a subsidiary of ARCO) to B&W PGG, B&W PGG received an indemnity and hold harmless from ARCO from claims or liabilities arising as a result of pre-closing Numec or ARCO actions. We believe that this indemnity should protect B&W PGG from claims caused by or arising from the actions of Numec or ARCO prior to B&W PGG’s acquisition of Numec.

In September 1998, a jury found B&W PGG and ARCO liable to eight plaintiffs in the first cases brought to trial, awarding $36.7 million in compensatory damages. During the trial, B&W PGG settled all pending punitive damages claims in the Hall Litigation for $8.0 million. In June 1999, the Pennsylvania District 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, which, following the commencement of the Chapter 11 Bankruptcy, the Third Circuit Court of Appeals declined to accept for review.

In July 1999, B&W PGG commenced a declaratory judgment action against its insurers, American Nuclear Insurers and Mutual Atomic Energy Liability Underwriters (collectively “ANI”), in Pennsylvania state court seeking, among other things, a judicial determination as to the amount of coverage available under four “facility form” nuclear energy liability policies that insure B&W PGG against, among other things, death, bodily injury and property damage caused or allegedly caused by the radioactive, toxic, explosive or other hazardous properties of nuclear material discharged from the nuclear fuel processing facilities at issue in the Hall Litigation. In April 2001, the Pennsylvania state court issued a ruling regarding: (1) the applicable “trigger of coverage” under the insurance policies; and (2) the scope of ANI’s defense obligations to B&W PGG under the insurance policies. With respect to the trigger of coverage, the Pennsylvania state court held that “manifestation” is an applicable trigger with respect to the underlying claims in the Hall Litigation. Although the Court did not make any specific determination with respect to any of the underlying claims, the effect of its ruling is to increase the total amount of coverage potentially available to B&W PGG for the claims alleged in the Hall Litigation under the insurance policies to $320 million, subject to decrease for defense costs. The Pennsylvania state court also held that ANI must pay for separate and independent counsel to represent B&W PGG

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in the Hall Litigation. ANI appealed and the Pennsylvania Superior Court affirmed. The Pennsylvania Supreme Court denied further discretionary review.

The Chapter 11 plan of reorganization, entered on February 22, 2006, did not impair the claims asserted in the Hall Litigation, which were permitted to pass through the Chapter 11 Bankruptcy unaffected by it. Accordingly, the Hall Litigation is proceeding in the Pennsylvania District Court.

In July 2007, the Pennsylvania District Court ordered separate trials on general causation for claims based upon uranium and plutonium exposure. A March 2008 trial on general causation as it relates to uranium has been postponed to allow the plaintiffs additional limited discovery. The trial on general causation as it relates to plutonium has not yet been scheduled. Any plaintiffs who may remain in the case following the “general causation” trials would be required to show “specific causation” in additional trial proceedings.

In December 2007, B&W PGG filed an action for breach of contract against ARCO in the Court of Common Pleas Allegheny County, Pennsylvania. In addition to its claim for breach of contract, B&W PGG seeks a declaratory judgment that ARCO is obligated to indemnify B&W PGG under the indemnity agreement between the two parties against any losses that B&W PGG may incur arising out of the nuclear fuel processing facilities at issue in the Hall Litigation. ARCO removed the declaratory judgment action to federal court and the case was assigned to the same judge handling the Hall Litigation. B&W PGG filed a motion to remand to state court, which has not yet been decided.

In February 2008, the plaintiffs and ARCO reached an agreement to settle ARCO’s exposure in the Hall Litigation and have asked the Pennsylvania District Court to approve the settlement. On February 19, B&W PGG filed objections to the settlement with the Court. The Court has made no decision on approval of the settlement.

We believe these claims will be resolved within the limits of coverage of our insurance policies and/or the ARCO indemnity. 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, the benefits of the ARCO indemnity and the amount we have reserved for these claims.

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 PGG. Additionally, Travelers filed a cross-claim requesting a declaration of non-coverage in approximately 20 underlying matters. This proceeding was stayed by the court on January 3, 2005.

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. 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 PGG supplied and installed the generators at issue. On March 20, 2007, the Court granted summary judgment in favor of all defendants and dismissed all claims of Iroquois Falls Power Corp., which appealed the ruling in April 2007. The Court of Appeals for Ontario heard arguments on appeal in November 2007 and has taken the matter under advisement.

In a proceeding entitled Antoine, et al. vs. J. Ray McDermott, Inc., et al., filed in the 24th Judicial District Court, Jefferson Parish, Louisiana, approximately 88 plaintiffs filed suit against approximately 215 defendants, including JRMI and Delta Hudson Engineering Corporation (“DHEC”), another affiliate of ours, generally alleging injuries for exposure to asbestos, and unspecified chemicals, metals and noise while the plaintiffs were allegedly employed as Jones Act seamen. On January 10, 2007, the District Court dismissed the Plaintiffs’ claims, without prejudice to

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their right to refile their claims. On January 29, 2007, in a matter entitled Boudreaux, et al v. McDermott, Inc., et al,. originally filed in the United States District Court for the Southern District of Texas, 21 plaintiffs originally named in the Antoine matter filed suit against JRMI, MI and approximately 30 other employer defendants, alleging Jones Act seaman status and generally alleging exposure to welding fumes, solvents, dyes, industrial paints and noise. Boudreaux was transferred to the United States District Court for the Eastern District of Louisiana on May 2, 2007. The District Court entered an order in September 2007 staying the matter until further order of the court due to the bankruptcy filing of one of the co-defendants. Additionally, on January 29, 2007, in a matter entitled Antoine, et al. v. McDermott, Inc., et al., filed in the 164 th Judicial District Court for Harris County, Texas, 43 plaintiffs originally named in the Antoine matter filed suit against JRMI, MI and approximately 65 other employer defendants and 42 maritime products defendants, alleging Jones Act seaman status and generally alleging personal injuries for exposure to asbestos and noise. On April 27, 2007, the District Court entered an order staying all activity and deadlines in this matter other than service of process and answer/appearance dates until further order of the court. The Plaintiffs seek monetary damages in an unspecified amount in both cases and attorneys’ fees in the new Antoine case.

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 then had a value of 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. With interest, the award value now exceeds $100 million. The Defendants applied for rehearing of this decision, which was denied in October 2006. We have aggressively pursued collection of these amounts and will continue to do so; however, 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

·	workers’ compensation claims, Jones Act claims, premises liability claims and other claims.

Based upon our prior experience, we do not expect that any 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 us in March 1994 that it would seek monetary sanctions and remedial and monitoring relief related to the Parks Facilities. The relief sought is related to potential groundwater contamination resulting from previous operations at the facilities. These facilities are currently owned by a subsidiary in our Government Operations segment. PADEP has advised us that it does not intend to assess any monetary sanctions, provided our Government Operations segment 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 our Government Operations segment have indicated that such remediation may not be necessary. Our Government Operations segment continues to evaluate closure of the groundwater issues pursuant to applicable Pennsylvania law.

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The NRC’s decommissioning regulations require our Government Operations segment 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. We will continue to provide financial assurance aggregating $24.5 million during the year ending December 31, 2008 with existing letters of credit for the ultimate decommissioning of all their licensed facilities, except one. This facility, which represents the largest portion of our 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 U.S. Department of Energy.

At December 31, 2007 and 2006, we had total environmental reserves (including provisions for the facilities discussed above) of $18.8 million and $18.6 million, respectively. Of our total environmental reserves at December 31, 2007 and 2006, $7.0 million and $9.6 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 that 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, 2007 are as follows (in thousands):

Fiscal Year Ending December 31,	Amount
2008	$	17,660
2009	$	9,402
2010	$	7,466
2011	$	4,226
2012	$	3,862
Thereafter	$	4,981

Total rental expense for the years ended December 31, 2007, 2006 and 2005 was $66.9 million, $52.0 million and $33.1 million, respectively. These expense amounts include contingent rentals and are net of sublease income, neither of which is material.

Other

We have been advised by the 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,

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we filed a protest with the IRS regarding the resolution of these issues and have met with an appellate conferee in this regard. 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 $15 million in excess of amounts provided for in our consolidated financial statements. In addition to this IRS matter, refer to Note 13 for information on the potential uncertainties associated with our reorganization of our U.S. tax groups.

NOTE 12 – 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 the following executive officers of our company 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, 2008 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: Bruce W. Wilkinson, Robert A. Deason, James Easter, Francis S. Kalman, John T. Nesser III and Louis J. Sannino. These elections, which apply to an aggregate of 82,200, 75,000, 11,700, 43,500, 28,200 and 18,300 shares vesting in the year ending December 31, 2008 and held by Messrs. Wilkinson, Deason, 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, 2007, each of Messrs. Wilkinson, Easter, Kalman, Nesser and Sannino made a similar election, which applied to an aggregate of 150,000, 24,000, 120,000, 63,000 and 48,000 shares, respectively, that vested in the year ended December 31, 2007. 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 4 for additional transactions with unconsolidated affiliates.

NOTE 13 – RISKS AND UNCERTAINTIES

As of December 31, 2007, 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, we had approximately $28 million in accounts and notes receivable due from our former joint venture in Mexico. A note receivable was attributable to the sale of our DB17 vessel during the quarter ended September 30, 2004. Due to the joint venture’s liquidity problems, we deferred recognition of a gain of approximately $5.4 million on the sale of the DB17 pending final settlement of the accounts and notes receivable. On October 17, 2006, we reached an agreement with its partner and terminated our interest in this joint venture. The financial impact of this transaction was included in our consolidated results of operations for the year ended December 31, 2006, including an impairment loss totaling approximately $16.4 million attributable to currency translation losses recorded in accumulated other comprehensive loss. During the year ended December 31, 2007, we received final payment from the entity, and the deferred gain of $5.4 million was recognized.

The reorganization of our 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

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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 14 – 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 37% of our trade receivables are due from foreign customers. See Note 18 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, 2007 and 2006, the allowance for possible losses that we deducted from accounts receivable – trade on the accompanying balance sheet was $5.2 million and $4.1 million, respectively.

NOTE 15 – INVESTMENTS

The following is a summary of our available-for-sale securities at December 31, 2007:

	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	(In thousands)

U.S. Treasury securities and obligations of U.S. Government agencies	$	91,845	$	907	$	-		$	92,752
Money market instruments and short term investments		341,777		1,532		-			343,309
Asset-Backed Securities and Collateralized Mortgage Obligations(1)		27,555		-		(1,455	)		26,100
Total(2)	$	461,177	$	2,439	$	(1,455	)	$	462,161

(1) Included in our Asset-Backed Securities and Collateralized Mortgage Obligations is approximately $18 million of commercial paper secured by prime mortgaged backed securities. These investments originally matured in August of 2007 but were extended. We have changed our investment policy effective August of 2007 to no longer invest in Asset-Backed Securities or Asset-Backed Commercial paper. These investments represent approximately 1.7% of our total cash and cash equivalents and investments at December 31, 2007.

(2) Fair value of $30.7 million pledged to secure payments under certain reinsurance agreements

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The following is a summary of our available-for-sale securities at December 31, 2006:

	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	(In thousands)

U.S. Treasury securities and obligations of U.S. Government agencies	$	89,557	$	-	$	(179	)	$	89,378
Money market instruments and short term investments		202,909		712		(1	)		203,620
Asset-Backed Securities and Collateralized Mortgage Obligations		1,087		-		-			1,087
Total(1)	$	293,553	$	712		(180	)	$	294,085
(1) Fair value of $36.0 million pledged to secure payments under certain reinsurance agreements

At December 31, 2007, all our available-for-sale debt securities have contractual maturities primarily between 2008 and 2010.

Proceeds, gross realized gains and gross realized losses on sales of available-for-sale securities were as follows:

	Proceeds		Gross Realized Gains		Gross Realized Losses
Year Ended December 31, 2007	$	2,311,730	$	177	$	-
Year Ended December 31, 2006	$	1,730,838	$	7	$	-
Year Ended December 31, 2005	$	11,030,512	$	-	$	5

NOTE 16 – DERIVATIVE FINANCIAL INSTRUMENTS

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, 2007, we had forward contracts to purchase or sell a net total notional value of $368.7 million in foreign currencies, primarily Euros and Canadian Dollars, at varying maturities through December 2011. At December 31, 2006, we had forward contracts to purchase or sell a net total of $211.1 million in foreign currencies, primarily Euros and Canadian Dollars, at varying maturities through September 2009.

At December 31, 2007, we had a foreign currency option contract outstanding to purchase 0.9 million Euros at a strike price of 1.34 with varying expiration dates extending to October 2008. Also at December 31, 2007, we had a foreign currency option contract to purchase 427.1 million Japanese Yen at a strike price of 110.0 with an expiration date of February 29, 2008. At December 31, 2006, we had a foreign currency option contract 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.

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We have designated substantially all of our forward and option 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, 2007 and 2006, we have deferred approximately $20.9 million and $9.4 million, respectively, of net gains on these derivative financial instruments. Of the deferred amount at December 31, 2007, 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, 2007, 2006 and 2005, we immediately recognized net losses of approximately $2.1 million, $4.1 million and $0.2 million, respectively, which primarily 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 17 – 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 that 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, 2007, we had net forward contracts outstanding to purchase or sell foreign currencies, primarily Euros and Canadian Dollars, with a total notional value of $368.7 million and a total fair value of $5.5 million.

The estimated fair values of our financial instruments are as follows:

	December 31, 2007				December 31, 2006
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)

Balance Sheet Instruments
Cash and Cash equivalents	$	1,001,394	$	1,001,394	$	600,843	$	600,843
Restricted cash and cash equivalents	$	64,786	$	64,786	$	106,674	$	106,674
Investments	$	462,161	$	462,161	$	294,085	$	294,085
Debt	$	17,208	$	17,421	$	272,734	$	275,648

NOTE 18 – SEGMENT REPORTING

Our reportable segments are Offshore Oil and Gas Construction, Government Operations and Power Generation Systems, as described in Note 1. The operations of our segments are managed separately and each has unique technology, services and customer class.

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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.

Due to the Chapter 11 Bankruptcy, we did not consolidate the results of operations for the primary operating subsidiaries in our Power Generation Systems segment from February 22, 2000 through February 22, 2006.

SEGMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005.

1. Information about Operations in our Different Industry Segments:

	Year Ended December 31,
	2007			2006(2)			2005(2)
	(In thousands)
REVENUES (1):
Offshore Oil and Gas Construction	$	2,445,675		$	1,610,307		$	1,238,870
Government Operations		694,024			630,067			601,042
Power Generation Systems		2,504,225			1,888,636			-
Adjustments and Eliminations		(12,314	)		(8,869	)		(172	)
	$	5,631,610		$	4,120,141		$	1,839,740

(1) Segment revenues are net of the following intersegment transfers and other adjustments:
Offshore Oil and Gas Construction Transfers	$	11,415		$	7,770		$	51
Government Operations Transfers		776			784			121
Power Generation Systems Transfers		123			315			-
	$	12,314		$	8,869		$	172

(2) Due to the Chapter 11 Bankruptcy, we did not consolidate the results of operations for the primary operating subsidiaries in our Power Generation Systems segment from February 22, 2000 through February 22, 2006.

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	Year Ended December 31,
	2007			2006(2)			2005(2)
	(In thousands)
OPERATING INCOME:

Segment Operating Income (Loss):
Offshore Oil and Gas Construction	$	397,560		$	214,105		$	157,470
Government Operations		90,022			82,744			67,983
Power Generation Systems		219,734			101,904			(891	)
	$	707,316		$	398,753		$	224,562

Gains (Losses) on Asset Disposal and Impairments – Net:
Offshore Oil and Gas Construction	$	6,765		$	(16,175	)	$	6,445
Government Operations		1,631			1,123			130
Power Generation Systems		(25	)		65			-
	$	8,371		$	(14,987	)	$	6,575

Equity in Income (Loss) of Investees:
Offshore Oil and Gas Construction	$	(3,923	)	$	(2,882	)	$	2,818
Government Operations		31,288			27,768			31,258
Power Generation Systems		14,359			12,638			6,447
	$	41,724		$	37,524		$	40,523

SEGMENT INCOME:
Offshore Oil and Gas Construction	$	400,402		$	195,048		$	166,733
Government Operations		122,941			111,635			99,371
Power Generation Systems		234,068			114,607			5,556
	$	757,411		$	421,290		$	271,660

Unallocated Corporate		(41,214	)		(29,949	)		(39,940	)
	$	716,197		$	391,341		$	231,720

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	Year Ended December 31,
	2007		2006(2)		2005(2)
	(In thousands)
SEGMENT ASSETS:
Offshore Oil and Gas Construction	$	2,044,740	$	1,299,883	$	1,008,906
Government Operations		494,707		336,750		300,223
Power Generation Systems		1,420,162		1,433,551		16,101
Total Segment Assets		3,959,609		3,070,184		1,325,230
Corporate Assets		451,877		563,578		384,732
Total Assets	$	4,411,486	$	3,633,762	$	1,709,962

CAPITAL EXPENDITURES:
Offshore Oil and Gas Construction	$	172,580	$	89,501	$	37,411
Government Operations		14,117		16,608		26,892
Power Generation Systems		40,218		23,718		-
Segment Capital Expenditures		226,915		129,827		64,303
Corporate Capital Expenditures		6,374		2,877		217
Total Capital Expenditures	$	233,289	$	132,704	$	64,520

DEPRECIATION AND AMORTIZATION:
Offshore Oil and Gas Construction	$	54,318	$	28,515	$	28,727
Government Operations		19,269		14,833		13,696
Power Generation Systems		21,266		16,342		-
Segment Depreciation and Amortization		94,853		59,690		42,423
Corporate Depreciation and Amortization		1,136		1,310		1,843
Total Depreciation and Amortization	$	95,989	$	61,000	$	44,266

INVESTMENT IN UNCONSOLIDATED AFFILIATES:
Offshore Oil and Gas Construction	$	7,339	$	6,662	$	5,812
Government Operations		3,983		4,404		7,303
Power Generation Systems		50,919		41,735		9,754
Total Investment in Unconsolidated Affiliates	$	62,241	$	52,801	$	22,869

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2. Information about our Product and Service Lines:

	Year Ended December 31,
	2007			2006(2)			2005(2)
	(In thousands)
REVENUES:
Offshore Oil and Gas Construction:
Offshore Operations	$	1,126,609		$	661,231		$	596,729
Fabrication Operations		413,940			307,759			126,807
Project Services and Engineering Operations		303,671			241,102			201,268
Procurement Activities		618,795			417,905			324,993
Eliminations		(17,340	)		(17,690	)		(10,927	)
		2,445,675			1,610,307			1,238,870
Government Operations:
Nuclear Component Program		619,154			533,468			509,560
Management & Operation Contracts of U.S. Government Facilities		18,776			10,628			5,594
Other Commercial Operations		3,853			11,879			24,637
Nuclear Environmental Services		51,703			44,833			42,174
Contract Research		1,877			5,426			9,886
Other Government Operations		708			25,830			14,082
Other Industrial Operations		-			913			160
Eliminations		(2,047	)		(2,910	)		(5,051	)
		694,024			630,067			601,042
Power Generation Systems:
Original Equipment Manufacturers’ Operations		1,371,427			916,889			-
Nuclear Equipment Operations		137,864			135,403			-
Aftermarket Goods and Services		829,185			693,578			-
Operations and Maintenance		54,854			47,057			-
Boiler Auxiliary Equipment		115,855			106,121			-
Eliminations		(4,960	)		(10,412	)		-
		2,504,225			1,888,636			-
Eliminations		(12,314	)		(8,869	)		(172	)
	$	5,631,610		$	4,120,141		$	1,839,740

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3. Information about our Operations in Different Geographic Areas:

	Year Ended December 31,
	2007		2006(2)		2005(2)
	(In thousands)
REVENUES(3):
United States	$	2,986,442	$	2,197,368	$	688,748
Azerbaijan		469,984		406,510		424,061
Saudi Arabia		367,651		256,484		89,145
Qatar		365,410		262,681		174,609
India		246,881		25,752		36,993
Canada		239,181		228,246		768
Australia		172,838		7,201		84,511
Malaysia		167,125		75,513		42,769
Vietnam		131,438		102,680		16,945
Thailand		130,419		129,753		52,209
Indonesia		102,560		161,023		42,743
Sweden		41,754		49,286		-
Denmark		36,382		45,438		-
Trinidad		36,220		27,213		11,310
China		32,903		42,199		-
Belgium		17,416		424		-
United Arab Emirates		10,598		-		776
United Kingdom		10,142		8,040		585
France		9,934		10,207		-
Germany		8,815		4,627		-
Mexico		3,657		39,204		82,697
Russia		1,165		4,477		89,928
Other Countries		42,695		35,815		943
	$	5,631,610	$	4,120,141	$	1,839,740
(3) We allocate geographic revenues based on the location of the customer’s operations.

PROPERTY, PLANT AND EQUIPMENT, NET(4):
United States	$	333,815	$	279,095	$	193,512
United Arab Emirates		154,113		60,707		36,932
Indonesia		145,549		74,259		34,366
Canada		114,472		34,529		-
Mexico		42,607		3,523		12,693
Australia		25,458		72		-
India		18,912		21,183		6,808
United Kingdom		14,587		5,340		-
Trinidad		12,763		-		-
Singapore		9,315		1,203		-
Denmark		8,943		8,403		-
Malaysia		186		16		31,558
Saudi Arabia		-		19,667		-
Other Countries		33,018		5,497		1,864
	$	913,738	$	513,494	$	317,733
(4) Our marine vessels are included in the country in which they are operating as of December 31, 2007.

4. Information about our Major Customers:

In the years ended December 31, 2007, 2006 and 2005, the U.S. Government accounted for approximately 12%, 15% and 31%, 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.

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NOTE 19 – QUARTERLY FINANCIAL DATA (UNAUDITED)

The following tables set forth selected unaudited quarterly financial information for the years ended December 31, 2007 and 2006:

	Year Ended December 31, 2007 Quarter Ended
	March 31, 2007		June 30, 2007		Sept. 30, 2007		Dec. 31, 2007
	(In thousands, except per share amounts)

Revenues	$	1,363,430	$	1,418,146	$	1,324,018	$	1,526,016
Operating income (1)	$	192,478	$	181,792	$	155,150	$	186,777
Equity in income from investees	$	7,241	$	7,308	$	12,477	$	14,698
Net income	$	158,061	$	149,374	$	140,408	$	159,985

Earnings per common share:
Basic:
Net income	$	0.72	$	0.67	$	0.63	$	0.71
Diluted:
Net income	$	0.69	$	0.66	$	0.61	$	0.70
(1) Includes equity in income from investees.

	Year Ended December 31, 2006 Quarter Ended
	March 31, 2006		June 30, 2006		Sept. 30, 2006		Dec. 31, 2006
	(In thousands, except per share amounts)

Revenues	$	644,907	$	1,048,930	$	1,118,260	$	1,308,044
Operating income (1)	$	67,728	$	112,711	$	124,100	$	86,802
Equity in income from investees	$	7,547	$	7,340	$	10,310	$	12,327
Net income	$	55,323	$	47,014	$	102,667	$	125,511

Earnings per common share:
Basic:
Net income	$	0.26	$	0.22	$	0.47	$	0.57
Diluted:
Net income	$	0.25	$	0.21	$	0.45	$	0.55
(1) Includes equity in income from investees.

Results for each quarter in the year ended December 31, 2006 have been adjusted for the change in accounting policy for drydocking costs, as discussed further in Note 1, and the stock splits effected in September 2007 and May 2006, as discussed further in Note 9.

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NOTE 20 – EARNINGS PER SHARE

The following table sets forth the computation of basic and diluted earnings per share:

	Year Ended December 31,
	2007		2006		2005
	(In thousands, except shares and per share amounts)
Basic:

Income from continuing operations	$	607,828	$	317,621	$	205,583
Income from discontinued operations		-		12,894		104
Net income for basic computation	$	607,828	$	330,515	$	205,687

Weighted average common shares		223,511,880		217,752,454		205,137,664

Basic earnings per common share:
Income from continuing operations	$	2.72	$	1.46	$	1.00
Income from discontinued operations		0.00		0.06		0.00
Net income	$	2.72	$	1.52	$	1.00

Diluted:

Income from continuing operations	$	607,828	$	317,621	$	205,583
Income from discontinued operations		-		12,894		104
Net income for diluted computation	$	607,828	$	330,515	$	205,687

Weighted average common shares (basic)		223,511,880		217,752,454		205,137,664
Effect of dilutive securities:
Stock options, restricted stock and performance shares		5,230,642		9,966,330		13,199,866
Adjusted weighted average common shares		228,742,522		227,718,784		218,337,530

Diluted earnings per common share:
Income from continuing operations	$	2.66	$	1.39	$	0.94
Income from discontinued operations		0.00		0.06		0.00
Net income	$	2.66	$	1.45	$	0.94

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NOTE 21 – PRO FORMA CONSOLIDATION (UNAUDITED)

On February 22, 2006, several subsidiaries included in our Power Generation Systems segment exited from the Chapter 11 Bankruptcy, which commenced on February 22, 2000. Due to the Chapter 11 Bankruptcy, we did not consolidate the results of operations for these subsidiaries in our consolidated financial statements from February 22, 2000 through February 22, 2006. The pro forma information below presents combined results of operations as if these subsidiaries 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.

	Year Ended December 31,
	2006		2005
	(In thousands)

Revenues	$	4,378,408	$	3,347,820
Operating Income (Loss) (1)	$	393,019	$	(183,752	)
Net Income (Loss) (2)	$	332,307	$	(57,084	)
Diluted Earnings (Loss) Per Share	$	1.46	$	(0.26	)

(1) Included in Operating Income (Loss) for the year ended December 31, 2005 is approximately $491 million of expenses related to asbestos and certain other liability claims and various expenses associated with the Chapter 11 Bankruptcy.

(2) Included in Net Income (Loss) for the year ended December 31, 2005 is approximately $314 million, net of tax, of expenses related to asbestos and certain other liability claims and various expenses associated with the Chapter 11 Bankruptcy.

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

For the years ended December 31, 2007 and 2006, we had no disagreements with Deloitte & Touche LLP on any accounting or financial disclosure issues. For the year ended December 31, 2005, we had no disagreements with PricewaterhouseCoopers LLP on any accounting or financial disclosure issues. The information required by this item is incorporated by reference to McDermott International, Inc.’s Current Report on Form 8-K filed March 31, 2006.

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, 2007 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.

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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, 2007, 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, 2007.

We completed the purchase of all of the capital stock of Marine Mechanical Corporation on May 1, 2007 and of substantially all the assets of Secunda International Limited on July 27, 2007. In conducting the Company’s evaluation of the effectiveness of its internal control over financial reporting, management excluded these acquired businesses from its 2007 internal control assessment, as permitted by the Securities and Exchange Commission. As of December 31, 2007, these acquired businesses represented approximately 8% of our consolidated revenues and approximately 9% of our consolidated total assets.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2007 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 the internal control over financial reporting of McDermott International, Inc. and subsidiaries (the "Company") as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Marine Mechanical Corporation and Secunda International Limited, acquired on May 1, 2007 and July 27, 2007, respectively, and whose financial statements constitute 9% of consolidated total assets, respectively, and a combined 8% of consolidated revenues of the consolidated financial statement amounts as of and for the year ended December 31, 2007. Accordingly, our audit did not include the internal control over financial reporting at Marine Mechanical Corporation and Secunda International Limited. 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, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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, 2007 of the Company and our report dated February 27, 2008 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the adoption of Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” as of January 1, 2007.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2008

Item 9B.

OTHER INFORMATION

On February 26, 2008, Bruce W. Wilkinson, Chairman and Chief Executive Officer, notified McDermott of his intention to retire as Chairman of our Board of Directors and Chief Executive Officer by December 31, 2008.

The Compensation Committee of our Board of Directors (the “Compensation Committee”) administers the Executive Incentive Compensation Plan (“EICP”), a cash bonus plan under which our executive officers participate. The payment amount, if any, of an EICP award is determined based on: (1) the attainment of financial performance measures, (2) the attainment of individual performance measures, and (3) the exercise of the Compensation Committee’s discretionary authority.

On February 26, 2008, our Compensation Committee established 2008 target award opportunities and confidential financial performance measures relative to those opportunities for our named executive officers, Messrs. Bruce W. Wilkinson, Robert A. Deason, John A. Fees, Francis S. Kalman, John T. Nesser III and Michael S. Taff. For the year ending December 31, 2008, the target award opportunities for these named executive officers are as follows:

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Named Executive Officer	Target Award Opportunity (as a percentage of 2008 base salary)
Bruce W. Wilkinson	100%
Robert A. Deason	70%
John A. Fees	70%
Francis S. Kalman	65%
John T. Nesser III	65%
Michael S. Taff	55%

For 2008, 85% of the target award opportunity is attributable to financial performance measures established by the Compensation Committee and 15% of the target award opportunity is attributable to individual performance measures determined by our Chief Executive Officer. The Compensation Committee retained its discretion to increase or decrease an award in its discretion.

The Compensation Committee established three levels of financial performance for determining the minimum, target and maximum payment under the financial performance component of the 2008 EICP award for these named executive officers. For our 2008 EICP awards, our Compensation Committee set the levels of financial performance based upon year-over-year increases in our consolidated operating income. For Messrs. Deason and Fees, the Compensation Committee divided the financial performance measure, with 60% attributable to the operating income of their respective business unit, J. Ray McDermott, S.A. or The Babcock & Wilcox Company, respectively, and 25% attributable to McDermott’s consolidated operating income.

Additionally, on February 25, 2008, our Compensation Committee approved the form of grant agreement to be used in connection with grants of performance shares and restricted stock to our officers and key employees pursuant to our 2001 Directors and Officers Long-Term Incentive Plan, as amended to date (“2001 LTIP”). A copy of the general form of agreement for grants of performance shares under the 2001 LTIP are included as exhibits to this annual report.

P A R T I I I

Item 10.

DIRECTORS, 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" and "Executive Officers," respectively, in the Proxy Statement for our 2008 Annual Meeting of Stockholders. The information required by this item with respect to compliance with section 16(a) of the Securities and Exchange Act of 1934, as amended, is incorporated by reference to the material appearing under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement for our 2008 Annual Meeting of Stockholders. The information required by this item with respect to the Audit Committee and Audit Committee financial experts is incorporated by reference to the material appearing in the “Committee” and “Audit Committee” sections under the heading “Corporate Governance – Board of Directors and Its Committees” in the Proxy Statement for our 2008 Annual Meeting of Stockholders.

We have adopted a Code of Business Conduct for our employees and directors, including, specifically, our chief executive officer, our chief financial officer, our chief accounting officer, and our other executive officers. Our code satisfies the requirements for a “code of ethics” within the meaning of SEC rules. A copy of the code is posted on our website, www.mcdermott.com/ under "Corporate Governance - Governance Policies - Code of Ethics for Chief Executive Officer and Senior Financial Officers."

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 2008 Annual Meeting of Stockholders.

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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, Related Stockholder Matters and Issuer Purchases of Equity Securities” 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 2008 Annual Meeting of Stockholders.

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information in Note 12 to our consolidated financial statements included in this report is incorporated by reference. Additional information required by this item is incorporated by reference to the material appearing under the heading “Corporate Governance – Director Independence” in the Proxy Statement for our 2008 Annual Meeting of Stockholders.

Item 14.

PRINCIPAL ACCOUNTANT 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, 2008” in the Proxy Statement for our 2008 Annual Meeting of Stockholders.

P A R T I V

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, 2007 and 2006
		Consolidated Statements of Income for the Years Ended December 31, 2007, 2006 and 2005
		Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, 2006 and 2005
		Consolidated Statements of Stockholders' Equity (Deficit) for the Years Ended December 31, 20007, 2006 and 2005
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005
		Notes to Consolidated Financial Statements for the Years Ended December 31, 2007, 2006 and 2005

	2.	CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
				Schedule II is 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
		Exhibit Number				Description

		3.1		McDermott International, Inc.'s Articles of Incorporation, as amended (incorporated by reference to Exhibit 3.1 to McDermott International, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-08430)).

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		3.2		McDermott International, Inc.'s Amended and Restated By-laws (incorporated by reference to Exhibit 3.1 to McDermott International, Inc.’s Current Report on Form 8-K dated May 3, 2006 (File No. 1-08430)).

		3.3		Amended and Restated Certificate of Designation of Series D Participating Preferred Stock (incorporated by reference to Exhibit 3.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001 (File No. 1-08430)).

		4.1		Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Credit Lyonnais New York Branch, as administrative agent, and Credit Lyonnais Securities, as lead arranger and sole bookrunner (incorporated by reference to Exhibit 4.8 of McDermott International, Inc.’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 (File No. 1-08430)).

		4.2		First Amendment, dated as of March 18, 2005, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated March 18, 2005 (File No. 1-08430)).

		4.3		Second Amendment, dated as of November 7, 2005, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended (incorporated by reference to Exhibit 4.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (File No. 1-08430)).

		4.4		Third Amendment, dated as of December 22, 2006, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended.

		4.5		Fourth Amendment, dated as of March 29, 2007, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended (incorporated by reference to Exhibit 4.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-08430)).

		4.6		Fifth Amendment, dated as of October 29, 2007, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated October 29, 2007 (File No. 1-08430)).

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	4.7	Credit Agreement dated as of June 6, 2006, by and among J. Ray McDermott, S.A., credit lenders, synthetic investors and issuers party thereto, Credit Suisse, Cayman Islands Branch, Bank of America, N.A., Calyon New York Branch, Fortis Capital Corp. and Wachovia Bank, National Association (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated June 6, 2006 (File No. 1-08430)).

	4.8	First Amendment to Credit Agreement, dated as of August 4, 2006, by and among, J. Ray McDermott, S.A., certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto.

	4.9	Second Amendment to Credit Agreement, dated as of December 1, 2006, by and among, J. Ray McDermott, S.A., certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto.

	4.10	Third Amendment to Credit Agreement, dated as of July 9, 2007, by and among, J. Ray McDermott, S.A., certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto (incorporated by reference to Exhibit 4.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-08430)).

	4.11	Fourth Amendment to Credit Agreement, dated as of July 20, 2007, by and among, J. Ray McDermott, S.A., certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K dated July 20, 2007 (File No. 1-08430)).

	4.12	Pledge and Security Agreement by J. Ray McDermott, S.A. and certain of its subsidiaries in favor of Credit Suisse, Cayman Islands Branch, as Administrative Agent and Collateral Agent, dated as of June 6, 2006 (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K dated June 6, 2006 (File No. 1-08430)).

	4.13	Credit Agreement dated as of February 22, 2006, by and among The Babcock & Wilcox Company, certain lenders, synthetic investors and issuers party thereto, Credit Suisse, Cayman Islands Branch, Credit Suisse Securities (USA) LLC, JPMorgan Chase Bank, National Association, Wachovia Bank, National Association and The Bank of Nova Scotia (incorporated by reference to Exhibit 10.4 to McDermott International, Inc.’s Current Report on Form 8-K dated February 21, 2006 (File No. 1-08430)).

	4.14	First Amendment to Credit Agreement, dated as of July 9, 2007, by and among, The Babcock & Wilcox Company, certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto (incorporated by reference to Exhibit 4.3 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-08430)).

	4.15	Second Amendment to Credit Agreement, dated as of July 20, 2007, by and among, The Babcock & Wilcox Company, certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated July 20, 2007 (File No. 1-08430)).

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4.16

Pledge and Security Agreement by The Babcock & Wilcox Company and certain of its subsidiaries in favor of Credit Suisse, Cayman Islands Branch, as Administrative Agent and Collateral Agent, dated as of February 22, 2006 (incorporated by reference to Exhibit 10.5 to McDermott International, Inc.’s Current Report on Form 8-K dated February 21, 2006 (File No. 1-08430)).

We and certain of our consolidated subsidiaries are parties to other debt instruments under which the total amount of securities authorized does not exceed 10% of our total consolidated assets. Pursuant to paragraph 4(iii)(A) of Item 601 (b) of Regulation S-K, we agree to furnish a copy of those instruments to the Commission on request.

	10.1*		McDermott International, Inc.'s Executive Incentive Compensation Plan (incorporated by reference to Appendix C to McDermott International, Inc.'s Proxy Statement for its Annual Meeting of Stockholders held on May 3, 2006, as filed with the Commission under a Schedule 14A (File No. 1-08430)).

	10.2*		McDermott International, Inc.'s 1992 Senior Management Stock Option Plan (incorporated by reference to Exhibit 10 to McDermott International, Inc.'s Annual Report on Form10-K/A for fiscal year ended March 31, 1994 filed with the Commission on June 27, 1994 (File No. 1-08430)).

	10.3*		McDermott International, Inc.'s Restated 1996 Officer Long-Term Incentive Plan, as amended (incorporated by reference to Appendix B to McDermott International, Inc.'s Proxy Statement for its Annual Meeting of Stockholders held on September 2, 1997, as filed with the Commission under a Schedule 14A (File No. 1-08430)).

	10.4*		McDermott International, Inc.'s 1997 Director Stock Program (incorporated by reference to Appendix A to McDermott International, Inc.'s Proxy Statement for its Annual Meeting of Stockholders held on September 2, 1997, as filed with the Commission under a Schedule 14A (File No. 1-08430)).

	10.5*		McDermott International, Inc.’s Amended and Restated 2001 Directors & Officers Long-Term Incentive Plan (incorporated by reference to Appendix B to McDermott International, Inc.’s Proxy Statement for its Annual Meeting of Stockholders held on May 3, 2006, as filed with the Commission under a Schedule 14A (File No. 1-08430)).

	10.6*		McDermott International, Inc. Supplemental Executive Retirement Plan, Effective January 1, 2005 (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K dated December 31, 2004 (File No. 1-08430)).

	10.7*		Change in Control Agreement dated June 30, 2004 between McDermott International, Inc. and John A. Fees (incorporated by reference to Exhibit 10.5 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (File No. 1-08430)).

	10.8*		Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and Bruce W. Wilkinson (incorporated by reference to Exhibit 10.20 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 1-08430)).

	10.9*		Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and Robert A. Deason (incorporated by reference to Exhibit 10.21 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 1-08430)).

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		10.10*			Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and Francis S. Kalman (incorporated by reference to Exhibit 10.22 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 1-08430)).

		10.11*			Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and John T. Nesser, III (incorporated by reference to Exhibit 10.23 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 1-08430)).

		10.12*			Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and Louis J. Sannino (incorporated by reference to Exhibit 10.24 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004) (File No. 1-08430)).

		10.13*			Change in Control Agreement, dated as of March 29, 2007, between McDermott International, Inc. and Michael S. Taff (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated March 26, 2007 (File No. 1-08430)).

		10.14*			Arrangement with Chief Financial Officer (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated March 26, 2007 (File No. 1-08430)).

		10.15*			McDermott International Inc. Executive Compensation Incentive Plan 2007 performance goals (incorporated by reference to McDermott International, Inc.’s Current Report on Form 8-K dated February 26, 2007 (File No. 1-08430)).

		10.16*			McDermott International, Inc. Executive Compensation Incentive Plan 2007 individual goals (incorporated by reference to Part II, Item 5 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-08430)).

		10.17*			Notice of Grant (Stock Options and Deferred Stock Units) (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K filed May 18, 2005 (File No. 1-08430)).

		10.18*			Form of 2001 LTIP Stock Option Grant Agreement (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K filed May 18, 2005 (File No. 1-08430)).

		10.19*			Form of 2001 LTIP Deferred Stock Unit Grant Agreement (incorporated by reference to Exhibit 10.3 to McDermott International, Inc.’s Current Report on Form 8-K dated May 12, 2005 (File No. 1-08430)).

		10.20*			Form of 2001 LTIP Stock Option Grant Agreement to Nonemployee Directors (incorporated by reference to Exhibit 10.5 to McDermott International, Inc.’s Current Report on Form 8-K dated May 12, 2005 (File No. 1-08430)).

		10.21*			Form of 2001 LTIP Restricted Stock Grant Agreement to Nonemployee Directors (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated May 3, 2006 (File No. 1-08430)).

		10.22*			Form of 2001 LTIP 2006 Performance Shares Grant Agreement (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K dated May 3, 2006 (File No. 1-08430)).

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		10.23*			Form of 2001 LTIP 2007 Performance Shares Grant Agreement (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated April 30, 2007 (File No. 1-08430)).

		10.24*			Summary of Arrangement with Named Executive Officer (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (File No. 1-08430)).

		10.25*			Separation Agreement between McDermott Incorporated and Francis S. Kalman dated February 8, 2008 (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated February 14, 2008 (File No. 1-08430)).

		10.26*			Form of 2001 LTIP 2008 Performance Shares Grant Agreement.

		10.27*			Form of 2001 LTIP 2008 Restricted Stock Grant Agreement.

		12.1			Ratio of Earnings to Fixed Charges.

		16.1			Letter from PricewaterhouseCoopers (incorporated by reference to Exhibit 16.1 to McDermott International, Inc.’s Current Report on Form 8-K dated March 27, 2006 (File No. 1-08430)).

		21.1			Significant Subsidiaries of the Registrant.

		23.1			Consent of PricewaterhouseCoopers LLP.

		23.2			Consent of Deloitte & Touche LLP.

		31.1			Rule 13a-14(a)/15d-14(a) certification of Chief Executive Officer.

		31.2			Rule 13a-14(a)/15d-14(a) certification of Chief Financial Officer.

		32.1			Section 1350 certification of Chief Executive Officer.

		32.2			Section 1350 certification of Chief Financial Officer.

Management contract or compensatory plan or arrangement.

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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

February 27, 2008	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		Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)
Bruce W. Wilkinson

/s/ Michael S. Taff		Senior Vice President and Chief Financial Officer (Principal Financial Officer and Duly Authorized Representative)
Michael S. Taff

/s/ Dennis S. Baldwin		Vice President and Chief Accounting Officer (Principal Accounting Officer and Duly Authorized Representative)
Dennis S. Baldwin

/s/ John F. Bookout, III		Director
John F. Bookout, III

/s/ Roger A. Brown		Director
Roger A. Brown

/s/ Ronald C. Cambre		Director
Ronald C. Cambre

/s/ Bruce DeMars		Director
Bruce DeMars

/s/ Robert W. Goldman		Director
Robert W. Goldman

/s/ Robert L. Howard		Director
Robert L. Howard

/s/ Oliver D. Kingsley, Jr.		Director
Oliver D. Kingsley, Jr.

/s/ D. Bradley McWilliams		Director
D. Bradley McWilliams

/s/ Thomas C. Schievelbein		Director
Thomas C. Schievelbein

February 27, 2008

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Schedule II

McDERMOTT INTERNATIONAL, INC.

VALUATION AND QUALIFYING ACCOUNTS

				Additions
Description	Balance at Beginning of Period			Charged to Costs and Expenses (1)			Charged to Other Accounts			Balance at End of Period

Valuation Allowance for Deferred Tax Assets (2)

Year Ended December 31, 2007	$	(152,950	)	$	52,333		$	-		$	(100,617	)

Year Ended December 31, 2006	$	(126,613	)	$	(226,337	)		-		$	(152,950	)

Year Ended December 31, 2005	$	(188,271	)	$	67,249		$	(5,591	)	$	(126,613	)

(1) Net of reductions and other adjustments, all of which are charged to costs and expenses
(2) Amounts charged to other accounts included in other comprehensive income (minimum pension liability)

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INDEX TO EXHIBITS

Exhibit

Number

Description

Sequentially

Numbered

Pages

3.1	McDermott International, Inc.'s Articles of Incorporation, as amended (incorporated by reference to Exhibit 3.1 to McDermott International, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-08430)).

3.2	McDermott International, Inc.'s Amended and Restated By-laws (incorporated by reference to Exhibit 3.1 to McDermott International, Inc.’s Current Report on Form 8-K dated May 3, 2006 (File No. 1-08430)).

3.3	Amended and Restated Certificate of Designation of Series D Participating Preferred Stock (incorporated by reference to Exhibit 3.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001 (File No. 1-08430)).

4.1	Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Credit Lyonnais New York Branch, as administrative agent, and Credit Lyonnais Securities, as lead arranger and sole bookrunner) (incorporated by reference to Exhibit 4.8 of McDermott International, Inc.’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 (File No. 1-08430)).

4.2	First Amendment, dated as of March 18, 2005, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8- K dated March 18, 2005 (File No. 1-08430)).

4.3	Second Amendment, dated as of November 7, 2005, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended (incorporated by reference to Exhibit 4.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005 (File No. 1-08430)).

4.4	Third Amendment, dated as of December 22, 2006, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended.

4.5	Fourth Amendment, dated as of March 29, 2007, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended (incorporated by reference to Exhibit 4.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-08430)).

4.6	Fifth Amendment, dated as of October 29, 2007, to the Revolving Credit Agreement dated as of December 9, 2003 among BWX Technologies, Inc., as borrower, certain subsidiaries of BWX Technologies, Inc. as guarantors, the initial lenders named therein, Calyon, New York Branch (formerly known as Credit Lyonnais New York Branch), as administrative agent and lender, as amended (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated October 29, 2007 (File No. 1-08430)).

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4.7	Credit Agreement dated as of June 6, 2006, by and among J. Ray McDermott, S.A., credit lenders, synthetic investors and issuers party thereto, Credit Suisse, Cayman Islands Branch, Bank of America, N.A., Calyon New York Branch, Fortis Capital Corp. and Wachovia Bank, National Association (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated June 6, 2006 (File No. 1-08430)).

4.8	First Amendment to Credit Agreement, dated as of August 4, 2006, by and among, J. Ray McDermott, S.A., certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto.

4.9	Second Amendment to Credit Agreement, dated as of December 1, 2006, by and among, J. Ray McDermott, S.A., certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto.

4.10	Third Amendment to Credit Agreement, dated as of July 9, 2007, by and among, J. Ray McDermott, S.A., certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto (incorporated by reference to Exhibit 4.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-08430)).

4.11	Fourth Amendment to Credit Agreement, dated as of July 20, 2007, by and among, J. Ray McDermott, S.A., certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K dated July 20, 2007 (File No. 1-08430)).

4.12	Pledge and Security Agreement by J. Ray McDermott, S.A. and certain of its subsidiaries in favor of Credit Suisse, Cayman Islands Branch, as Administrative Agent and Collateral Agent, dated as of June 6, 2006 (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K dated June 6, 2006 (File No. 1-08430)).

4.13	Credit Agreement dated as of February 22, 2006, by and among The Babcock & Wilcox Company, certain lenders, synthetic investors and issuers party thereto, Credit Suisse, Cayman Islands Branch, Credit Suisse Securities (USA) LLC, JPMorgan Chase Bank, National Association, Wachovia Bank, National Association and The Bank of Nova Scotia (incorporated by reference to Exhibit 10.4 to McDermott International, Inc.’s Current Report on Form 8-K dated February 21, 2006 (File No. 1-08430)).

4.14	First Amendment to Credit Agreement, dated as of July 9, 2007, by and among, The Babcock & Wilcox Company, certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto (incorporated by reference to Exhibit 4.3 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 1-08430)).

4.15	Second Amendment to Credit Agreement, dated as of July 20, 2007, by and among, The Babcock & Wilcox Company, certain guarantors thereto, certain lenders and issuers party thereto, Credit Suisse, Cayman Islands Branch, as administrative agent and collateral agent, and other agents party thereto (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated July 20, 2007 (File No. 1-08430)).

4.16	Pledge and Security Agreement by The Babcock & Wilcox Company and certain of its subsidiaries in favor of Credit Suisse, Cayman Islands Branch, as Administrative Agent and Collateral Agent, dated as of February 22, 2006 (incorporated by reference to Exhibit 10.5 to McDermott International, Inc.’s Current Report on Form 8-K dated February 21, 2006 (File No. 1-08430)).

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10.1	McDermott International, Inc.'s Executive Incentive Compensation Plan (incorporated by reference to Appendix C to McDermott International, Inc.'s Proxy Statement for its Annual Meeting of Stockholders held on May 3, 2006, as filed with the Commission under a Schedule 14A (File No. 1-08430)).

10.2	McDermott International, Inc.'s 1992 Senior Management Stock Option Plan (incorporated by reference to Exhibit 10 to McDermott International, Inc.'s Annual Report on Form10-K/A for fiscal year ended March 31, 1994 filed with the Commission on June 27, 1994 (File No. 1-08430)).

10.3	McDermott International, Inc.'s Restated 1996 Officer Long-Term Incentive Plan, as amended (incorporated by reference to Appendix B to McDermott International, Inc.'s Proxy Statement for its Annual Meeting of Stockholders held on September 2, 1997, as filed with the Commission under a Schedule 14A (File No. 1-08430)).

10.4	McDermott International, Inc.'s 1997 Director Stock Program (incorporated by reference to Appendix A to McDermott International, Inc.'s Proxy Statement for its Annual Meeting of Stockholders held on September 2, 1997, as filed with the Commission under a Schedule 14A (File No. 1-08430)).

10.5	McDermott International, Inc.’s Amended and Restated 2001 Directors & Officers Long-Term Incentive Plan (incorporated by reference to Appendix B to McDermott International, Inc.’s Proxy Statement for its Annual Meeting of Stockholders held on May 3, 2006, as filed with the Commission under a Schedule 14A (File No. 1-08430)).

10.6	McDermott International, Inc. Supplemental Executive Retirement Plan, Effective January 1, 2005 (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K dated December 31, 2004 (File No. 1-08430)).

10.7	Change in Control Agreement dated June 30, 2004 between McDermott International, Inc. and John A. Fees (incorporated by reference to Exhibit 10.5 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (File No. 1-08430)).

10.8	Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and Bruce W. Wilkinson (incorporated by reference to Exhibit 10.20 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 1-08430)).

10.9	Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and Robert A. Deason (incorporated by reference to Exhibit 10.21 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 1-08430)).

10.10	Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and Francis S. Kalman (incorporated by reference to Exhibit 10.22 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 1-08430)).

10.11	Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and John T. Nesser, III (incorporated by reference to Exhibit 10.23 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 1-08430)).

10.12	Change in Control Agreement dated March 30, 2005 between McDermott International, Inc. and Louis J. Sannino (incorporated by reference to Exhibit 10.24 to McDermott International, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 1-08430)).

10.13	Change in Control Agreement, dated as of March 29, 2007, between McDermott International, Inc. and Michael S. Taff (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated March 26, 2007 (File No. 1-08430)).

10.14	Arrangement with Chief Financial Officer (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated March 26, 2007 (File No. 1-08430)).

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10.15	McDermott International Inc. Executive Compensation Incentive Plan 2006 Performance Goals (incorporated by reference to McDermott International, Inc.’s Current Report on Form 8-K dated February 27, 2006 (File No. 1-08430)).

10.16	McDermott International, Inc. Executive Compensation Incentive Plan 2007 individual goals (incorporated by reference to Part II, Item 5 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-08430)).

10.17	Notice of Grant (Stock Options and Deferred Stock Units) (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K filed May 18, 2005 (File No. 1-08430)).

10.18	Form of 2001 LTIP Stock Option Grant Agreement (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K filed May 18, 2005 (File No. 1-08430)).

10.19	Form of 2001 LTIP Deferred Stock Unit Grant Agreement (incorporated by reference to Exhibit 10.3 to McDermott International, Inc.’s Current Report on Form 8-K dated May 12, 2005 (File No. 1-08430)).

10.20	Form of 2001 LTIP Stock Option Grant Agreement to Nonemployee Directors (incorporated by reference to Exhibit 10.5 to McDermott International, Inc.’s Current Report on Form 8-K dated May 12, 2005 (File No. 1-08430)).

10.21	Form of 2001 LTIP Restricted Stock Grant Agreement to Nonemployee Directors (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated May 3, 2006 (File No. 1-08430)).

10.22	Form of 2001 LTIP 2006 Performance Shares Grant Agreement (incorporated by reference to Exhibit 10.2 to McDermott International, Inc.’s Current Report on Form 8-K dated May 3, 2006 (File No. 1-08430)).

10.23	Form of 2001 LTIP 2007 Performance Shares Grant Agreement (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated April 30, 2007 (File No. 1-08430)).

10.24	Summary of Arrangement with Named Executive Officer (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007 (File No. 1-08430)).

10.25	Separation Agreement between McDermott Incorporated and Francis S. Kalman dated February 8, 2008 (incorporated by reference to Exhibit 10.1 to McDermott International, Inc.’s Current Report on Form 8-K dated February 14, 2008 (File No. 1-08430)).

10.26	Form of 2001 LTIP 2008 Performance Shares Grant Agreement.

10.27	Form of 2001 LTIP 2008 Restricted Stock Grant Agreement.

12.1	Ratio of Earnings to Fixed Charges.

16.1	Letter from PricewaterhouseCoopers (incorporated by reference to Exhibit 16.1 to McDermott International, Inc.’s Current Report on Form 8-K dated March 27, 2006 (File No. 1-08430)).

21.1	Significant Subsidiaries of the Registrant.

23.1	Consent of PricewaterhouseCoopers LLP.

23.2	Consent of Deloitte & Touche LLP.

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31.1	Rule 13a-14(a)/15d-14(a) certification of Chief Executive Officer.

31.2	Rule 13a-14(a)/15d-14(a) certification of Chief Financial Officer.

32.1	Section 1350 certification of Chief Executive Officer.

32.2	Section 1350 certification of Chief Financial Officer.

REPUBLIC OF PANAMA	72-0593134
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
777 N. ELDRIDGE PKWY.
HOUSTON, TEXAS	77079
(Address of Principal Executive Offices)	(Zip Code)

	Name of each Exchange
Title of each class	on which registered
Common Stock, $1.00 par value	New York Stock Exchange

NAME OF COMPANY	JURISDICTION OF ORGANIZATION	PERCENTAGE OF OWNERSHIP INTEREST

J. Ray McDermott, S.A.	Panama	100
J. Ray McDermott International, Inc.	Panama	100
J. Ray McDermott Middle East, Inc.	Panama	100
McDermott Caspian Contractors, Inc.	Panama	100

McDermott Panama Holdings, S.A.	Panama	100
McDermott Holdings, Inc.	Delaware	100
McDermott Incorporated	Delaware	100
The Babcock & Wilcox Company	Delaware	100
BWX Technologies, Inc.	Delaware	100
Babcock & Wilcox Power Generation Group, Inc.	Delaware	100

Dated: February 27, 2008	/s/ Bruce W. Wilkinson
	Bruce W. Wilkinson
	Chairman of the Board and Chief Executive Officer