Edgar Filing: ROWAN COMPANIES INC

form10_k.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

R	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2010

OR

£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________

Commission File Number: 1-5491

ROWAN COMPANIES, INC.

(Exact name of registrant as specified in its charter)

Delaware	75-0759420
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

2800 Post Oak Boulevard, Suite 5450

Houston, Texas 77056-6189

Registrant’s telephone number, including area code: (713) 621-7800

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, $0.125 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes R No £

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes £ No R

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No £

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer R Accelerated filer £ Non-accelerated filer £ Smaller reporting company £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No R

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $2,487.8 million as of June 30, 2010, based upon the closing price of the registrant’s Common Stock on the New York Stock Exchange Composite Tape of $21.94 per share.

The number of shares of Common Stock, $0.125 par value, outstanding at January 31, 2011, was 126,327,816.

DOCUMENTS INCORPORATED BY REFERENCE

Document	Part of Form 10-K
Portions of the Proxy Statement for the 2011 Annual Meeting of Stockholders	Part III, Items 10-14

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TABLE OF CONTENTS

	Page
PART I
Item 1. Business	3
Drilling Operations	3
Offshore Operations	3
Onshore Operations	4
Contracts	5
Competition	5
Governmental Regulation	6
Manufacturing Operations	6
Drilling Products and Systems	7
Mining, Forestry and Steel Products	7
Raw Materials	8
Competition	8
Governmental Regulation	8
Employees	8
Customers	9
Item 1A. Risk Factors	9
Item 1B. Unresolved Staff Comments	15
Item 2. Properties	16
Drilling Rigs	16
Manufacturing Facilities	17
Item 3. Legal Proceedings	18
Executive Officers of the Registrant	18

PART II
Item 5. Market for Registrant’s Common Stock, Related Stockholder Matters, and Issuer Purchases of Equity Securities	19
Item 6. Selected Financial Data	22
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A. Quantitative and Qualitative Disclosures about Market Risks	42
Item 8. Financial Statements and Supplementary Data	42
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	74
Item 9A. Controls and Procedures	74
Item 9B. Other Information	74

PART III
Item 10. Directors, Executive Officers and Corporate Governance	74
Item 11. Executive Compensation	74
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	75
Item 13. Certain Relationships and Related Transactions, and Director Independence	75
Item 14. Principal Accounting Fees and Services	75

PART IV
Item 15. Exhibits and Financial Statement Schedules	76

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FORWARD-LOOKING STATEMENTS

This Form 10-K contains “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”). Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:

·	statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;

·	statements relating to future financial performance, future capital sources and other matters; and

·	any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions.

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-K are reasonable, we can give no assurance that such plans, intentions and expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance, and actual results or developments may differ materially from those projected in the forward-looking statements. Among the factors that could cause actual results to differ materially are the following:

·	worldwide demand for drilling services

·	worldwide demand and prices for oil, natural gas and other commodities

·	the level of exploration and development expenditures by energy companies

·	the willingness and ability of the Organization of Petroleum Exporting Countries, or OPEC, to limit production levels and influence prices

·	the level of production in non-OPEC countries

·	the general economy, including inflation

·	the condition of global capital markets

·	weather and climate conditions in our principal operating areas, including possible disruption of exploration and development activities due to hurricanes and other severe weather conditions

·	environmental and other laws and regulations

·	policies of various governments regarding exploration and development of oil and natural gas reserves

·	domestic and international tax policies

·	political and military conflicts in oil-producing areas and the effects of terrorism

·	advances in exploration and development technology

·	further consolidation of our customer base

·	further consolidation of our competitors

All forward-looking statements contained in this Form 10-K speak only as of the date of this document. We undertake no obligation to update or revise publicly any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-K, or to reflect the occurrence of unanticipated events.

Other relevant factors are included in Item 1A, “Risk Factors,” of this Form 10-K.

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PART I

ITEM 1. BUSINESS

Rowan Companies, Inc. (“Rowan” or the “Company”) is a major provider of international and domestic contract drilling services. Rowan also owns and operates a manufacturing division that produces equipment for the drilling, mining and timber industries. Organized in 1947 as a Delaware corporation under the name Rowan Drilling Company, Inc., Rowan is a successor to a contract drilling business conducted since 1923.

Information with respect to Rowan’s revenues, operating income, assets, and other financial information relating to the Company’s business segments and geographic areas of operation is presented in Note 11 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) are made available free of charge on our website at www.rowancompanies.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

DRILLING OPERATIONS

Rowan provides contract drilling services utilizing a fleet of 28 self-elevating mobile offshore drilling platforms (“jack-up rigs”) and 30 deep-well land drilling rigs. Our primary focus is on high-specification and premium jack-up rigs, which our customers use for offshore exploratory and development drilling and, in certain areas, well workover operations.

We conduct offshore drilling operations in various markets throughout the world, and onshore drilling operations in the United States. At February 25, 2011, we had ten offshore rigs in the Middle East, ten in the U.S. Gulf of Mexico, five in or en route to the North Sea, and one each offshore Trinidad, Mexico and Egypt. At that date, we had eighteen land rigs in Texas, eight in Louisiana, two in Oklahoma and one each in Alabama and Alaska.

In September 2010, we completed our acquisition of Skeie Drilling & Production ASA (“SKDP),” a Norwegian entity that owned and managed the construction of three high-spec jack-up rigs, designated “N-Class,” being designed and built by Keppel FELS Ltd. in Singapore. We accounted for the transaction as an asset acquisition. The first two rigs, the Rowan Viking and Rowan Stavanger, were delivered in October 2010 and January 2011, respectively, and the third rig, which is to be named the Rowan Norway, is expected to be delivered in June 2011.

During 2010, our drilling operations generated revenues of $1,208.8 million and income from operations of $399.0 million, compared with $1,214.9 million and $472.1 million, respectively, in 2009. Our results of operations are further discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K.

Offshore Operations

Rowan operates large jack-up rigs capable of drilling depths up to 35,000 feet in maximum water depths ranging from 250 to 550 feet, depending on rig size and location. Our jack-ups are designed with a hull that is fully equipped to serve as a drilling platform supported by three independently elevating legs. The rig is towed to the drilling site where the legs are lowered until they penetrate the ocean floor, and the hull is jacked up to the elevation required to drill the well.

We have aggressively grown our jack-up fleet over the past decade to better serve the needs of the industry for drilling in harsher environments, and we are particularly well positioned to serve the niche market for high-pressure/high-temperature (“HPHT”) wells. All of our rigs feature top-drive drilling systems, solids-control equipment, AC power and mud pumps that greatly accelerate the drilling process. Most have been designed or upgraded to handle the toughest environmental criteria. At February 25, 2011, our offshore drilling fleet comprised the following:

•

Sixteen high-specification cantilever jack-up rigs, including one Gorilla class rig, two N-Class rigs, four enhanced Super Gorilla class rigs, four Tarzan Class rigs, two 240C class rigs, and three EXL class rigs, as described below. We use the term “high-specification” to describe the most capable jack-ups; i.e., those having a hook-load capacity of at least two million pounds.

•

Nine premium cantilever jack-up rigs, including two Gorilla class rigs and seven 116-C class rigs. We use the term “premium jack-ups” to denote independent-leg cantilever rigs that can operate in at least 300 feet of water in benign environments.

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•

Three conventional or slot jack-up rigs with skid-off capability.

Cantilever jack-ups can extend a portion of the sub-structure containing the drilling equipment over fixed production platforms to perform drilling operations with a minimum of interruption to production. Our conventional jack-ups use “skid-off” technology, which allows the rig floor drilling equipment to be “skidded” out over the top of a fixed platform, enabling these slot type jack-up rigs to be used on drilling assignments that would otherwise require a cantilever jack-up or platform rig.

Our Gorilla class rigs, designed in the early 1980s as a heavier-duty class of jack-up rig, are capable of operating in water depths up to 328 feet in extreme hostile environments (winds up to 100 miles per hour and seas up to 90 feet) such as the North Sea and offshore eastern Canada. Gorillas II and III can drill to 30,000 feet, and Gorilla IV is equipped to reach 35,000 feet.

Our four Super Gorilla class rigs were delivered during the period from 1998 to 2003 and are enhanced versions of our Gorilla class rigs that can be equipped for simultaneous drilling and production operations. They can operate year-round in 400 feet of water south of the 61st parallel in the North Sea, within the worst-case combination of 100-year storm criteria for waves, wave periods, winds and currents. The Bob Palmer (formerly the Gorilla VIII), is an enhanced version of the Super Gorilla class jack-up and is designated a Super Gorilla XL. With 713 feet of leg, 139 feet more than the Super Gorillas, and 30% larger spud cans, this rig can operate in water depths to 550 feet in relatively benign environments like the Gulf of Mexico and the Middle East or in water depths to 400 feet in the hostile environments of the North Sea and offshore eastern Canada and West Africa.

Our four Tarzan Class rigs were specifically designed for deep-well, HPHT drilling in up to 300 feet of water in benign environments.

Our 240C class rigs are designed for HPHT drilling in water depths to 400 feet. The first and second 240Cs, the Rowan-Mississippi and Ralph Coffman, were added to the fleet in 2008 and 2009, respectively. The third 240C, the Joe Douglas, is currently under construction with delivery expected in the third quarter of 2011.

Our EXL class rigs employ the latest technology to enable drilling of HPHT and extended-reach wells in most of the prominent jack-up markets throughout the world, and are equipped with the hook-load and horsepower required to efficiently drill beyond 30,000 feet. We accepted delivery in 2010 of the first three of our four EXL class rigs built at the Keppel AmFELS, Inc. shipyard in Brownsville, Texas. The EXL IV is expected to be delivered in the fourth quarter of 2011.

The N-Class rigs are capable of drilling up to 35,000 feet in harsh environments such as the North Sea, in maximum water depths of 450 feet. The N-Class rigs, which are designed for operation in the highly regulated Norwegian sector of the North Sea, can be equipped to perform drilling and production operations simultaneously. Our first two N-Class rigs, the Rowan Viking and Rowan Stavanger, were delivered in October 2010 and January 2011, respectively, and our third, which is to be named the Rowan Norway, is expected to be delivered in June 2011.

Rowan’s drilling operations are subject to many hazards, including blowouts, well fires and severe weather, which could cause personal injury, suspend drilling operations, seriously damage or destroy equipment, and cause substantial damage to producing formations and the surrounding environment. Offshore drilling rigs are also subject to marine hazards, either while on site or under tow, such as vessel capsizing, collision or grounding. Raising and lowering the legs of jack-up rigs into the ocean floor requires skillful handling to avoid capsizing or other serious damage. Drilling into high-pressure formations is a complex process and problems can frequently occur. See Item 1A, “Risk Factors,” of this Form 10-K for additional information.

Onshore Operations

In addition to our offshore drilling operations, we provide drilling equipment and personnel on a contract basis for exploration and development of onshore areas. At February 25, 2011, our onshore fleet consisted of 30 deep-well land rigs, 28 of which are 2,000 HP or greater and capable of drilling wells to 35,000 feet. Nineteen of our land rigs are AC drive. These premium specifications are ideal for extended-reach drilling in the Louisiana and Texas shale plays such as the Haynesville, Deep Bossier and Eagle Ford.

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A key element of our strategy has been to separate our land drilling operations from our core offshore drilling business when market conditions were suitable. We believe conditions are suitable now and expect to begin a process in 2011 to monetize this business. Our land drilling operations contributed approximately one-tenth of our consolidated revenues in 2010.

See Item 2, “Properties,” of this Form 10-K for additional information with respect to the rigs in our fleets.

Contracts

Our drilling contracts generally provide for a fixed amount of compensation per day, known as the day rate, and are usually obtained either through competitive bidding or individual negotiations.

Our drilling contracts are either “well-to-well,” “multiple-well” or for a fixed term generally ranging from one month to multiple years. Well-to-well contracts are cancelable by either party upon completion of drilling. Fixed-term contracts usually provide for termination by either party if drilling operations are suspended for extended periods as a result of events of force majeure. While many fixed-term contracts are for relatively short periods, some can continue for periods longer than the original terms, and well-to-well contracts can be extended over multiple series of wells. Many drilling contracts contain renewal or extension provisions exercisable at the option of the customer at mutually-agreeable rates and, in certain cases, such option rates are agreed-upon at the outset of the contract. Many of our drilling contracts provide for separate lump-sum payments for rig mobilization and demobilization, for which we recognize the revenues and related expenses over the primary contract term, and for reimbursement of certain other costs, for which we recognize both revenues and expenses when incurred. Our contracts for work in foreign countries generally provide for payment in United States dollars except for minimal amounts required to meet local expenses.

A number of factors affect our ability to obtain contracts, both onshore and offshore, at profitable rates within a given area. Such factors, which are discussed further under “Competition,” include the location and availability of competitive equipment, the suitability of equipment for the project, comparative operating cost of the equipment, competence of drilling personnel and other competitive factors. Profitability may also depend on receiving adequate compensation for the cost of moving equipment to drilling locations.

During periods of weak demand and declining day rates, we have historically accepted lower rates in an attempt to keep our rigs working and to mitigate the substantial costs of maintaining and reactivating stacked rigs. In 2010, however, we decided to cold-stack two of our least competitive rigs. In periods of strong demand and rising day rates, we strive to maintain a mix of short- and long-term contracts to enable us to both take advantage of potential higher future rates (and cover potential higher operating costs) as well as provide down-side protection when markets inevitably decline.

Our drilling revenue backlog was estimated to be approximately $1.8 billion at February 25, 2011, up from approximately $1.3 billion one year earlier. We estimate approximately 44% of our current backlog will be realized in 2011.

Competition

The contract drilling industry is highly competitive, and success in obtaining contracts involves many factors, including price, rig capability, operating and safety performance and reputation.

Currently, we compete with several offshore drilling contractors that together have 733 mobile rigs available worldwide, including 474 jack-ups. We estimate that 32 or less than 7% of the world’s existing jack-up fleet as of February 25, 2011, are high-specification, including the 16 rigs that we own. Sixty-seven additional jack-up rigs are under construction for delivery through 2014, seventeen of which are considered high-specification, including our three rigs under construction.

Based on the number of rigs as tabulated by ODS-Petrodata, Rowan is the seventh largest offshore drilling contractor in the world and the fifth largest jack-up rig operator. Some of our competitors have greater financial and other resources and may be more able to make technological improvements to existing equipment or replace equipment that becomes obsolete. In addition, those contractors with larger and more diversified drilling fleets may be better positioned to withstand unfavorable market conditions.

Our onshore operations compete with several domestic drilling contractors that have approximately 250 deep-well land rigs available.

We market our drilling services by contacting present and potential customers, including large international energy companies, many smaller energy companies and foreign government-owned or -controlled energy companies. See

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“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K for a discussion of current and anticipated industry conditions and their impact on our operations.

Governmental Regulation

Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation. In addition, the United States and other countries in which we operate have regulations relating to environmental protection and pollution control. Rowan could become liable for damages resulting from pollution of offshore waters and, under United States regulations, we must document financial responsibility. Generally, we are indemnified under our drilling contracts for pollution damages, except in certain cases of pollution emanating above the surface of land or water from spills of pollutants, or pollutants emanating from our drilling rigs. We can provide no assurance, however, that such indemnification provisions can be enforced or will be sufficient.

In response to the Deepwater Horizon incident on April 20, 2010, and subsequent oil spill, the U.S. Secretary of the Interior on May 27, 2010, announced a moratorium on U.S. offshore deepwater drilling, which was subsequently lifted on October 12, 2010. In addition, the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”), which was formerly known as the Minerals Management Service, issued Notices to Lessees (“NTLs”) implementing new safety regulations applicable to drilling operations in the Gulf of Mexico. These NTLs have adversely impacted the ability of our customers to obtain necessary permits and approval on a timely basis and/or to continue operations uninterrupted under existing permits. On October 15, 2010, the BOEMRE issued new regulations which formalized many of the requirements set forth in the NTLs and issued additional environmental and safety requirements. We have been evaluating our own safety programs and are working with our customers to meet these requirements; however, compliance with these new regulatory requirements may result in interruption of operations, reduced revenues, and higher operating costs.

We believe we are in compliance in all material respects with the health, safety and environmental regulations affecting the operation of our rigs and the drilling of oil and gas wells in the countries and jurisdictions in which we operate. Except as discussed above, regulatory compliance has not materially affected our capital expenditures, earnings or competitive position to date, although such measures do increase drilling costs and may adversely affect drilling operations. Further regulations may reasonably be anticipated, but any effects on our drilling operations cannot be accurately predicted at this time.

In the United States, Rowan is subject to the requirements of OSHA and comparable state statutes. OSHA requires us to provide our employees with information about the chemicals used in our operations. There are comparable requirements in other non-U.S. jurisdictions in which we operate.

In addition to the federal, state, and foreign regulations that directly affect our operations, regulations associated with the production and transportation of oil and gas affect the operations of our customers and thereby could potentially impact demand for our services.

MANUFACTURING OPERATIONS

Our manufacturing operations are conducted by LeTourneau Technologies, Inc. (“LeTourneau”), a wholly-owned subsidiary of the Company headquartered in Houston, Texas. LeTourneau has two operating segments – Drilling Products and Systems and Mining, Forestry and Steel Products, each of which serves markets that require large-scale, steel-intensive, high load-bearing products and related parts and services.

A key element of our strategy has been to separate our manufacturing operations from our core offshore drilling operations when market conditions were suitable. We believe conditions are suitable now and expect to begin a process in 2011 to sell or spin off our manufacturing operations. Our manufacturing operations contributed approximately one-third of our consolidated revenues in 2010.

In 2010, our manufacturing operations reported external revenues of $610.4 million and a loss from operations of $8.0 million, compared with revenues of $555.3 million and operating income of $28.9 million in 2009. Results for 2010 included a charge to operations of $42.0 million in connection with an inventory valuation adjustment. For further discussion, see “Inventories” in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. Our backlog of external manufacturing orders totaled approximately $299 million at December 31, 2010, nearly all of which is scheduled for delivery in 2011, compared with $413 million at December 31, 2009. Our manufacturing results of operations and backlog are further discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K.

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Drilling Products and Systems

Our Drilling Products and Systems segment built the first jack-up drilling rig in 1955, and has since designed, built or licensed the construction of more than 200 units including 26 of the 28 jack-ups in our fleet. This segment also designs and manufactures primary drilling equipment in a wide range of sizes, including mud pumps, top drives, drawworks and rotary tables, as well as variable-speed motors, variable-frequency drive systems and other electrical components for the oil and gas, marine, mining and dredging industries. We also manufacture complete land rigs and related drilling equipment packages.

Drilling Products and Systems is currently constructing our third 240C class jack-up, the Joe Douglas, at our Vicksburg, Mississippi, shipyard for delivery in the third quarter of 2011. Our Longview, Texas, facility provided the rig kit (design, legs, jacking system, cranes and other equipment) and our Houston, Texas, facility provided certain of the drilling equipment for each of our four EXL class jack-ups built for Rowan by Keppel, including the EXL IV currently under construction.

The Vicksburg facility is dedicated primarily to vessel construction for the offshore drilling industry, and is heavily dependent upon demand for offshore jack-up rigs. We currently have no further plans for rig construction in Vicksburg following the delivery of the Joe Douglas in 2011, but may continue to use the facility for other operations. Absent additional orders or sufficient prospects for future work, the activities at the facility would be significantly reduced at that time, in which case we would incur additional costs such as employee severance, among other charges. Closing or significantly reducing activity levels at the facility could result in the incurrence of cash charges ranging from $8 million to $10 million. Rig component manufacturing and design engineering continue to be performed at our Longview facility.

Mining, Forestry and Steel Products

Our Mining, Forestry and Steel Products segment manufactures heavy equipment such as large-wheeled front-end loaders, diesel-electric powered log stackers and steel plate products.

Our mining loaders feature bucket capacities up to 53 cubic yards, which are the largest in the industry. LeTourneau loaders are generally used in coal, copper, and iron ore mines, and utilize a proprietary diesel-electric hybrid drive system with digital controls. This system allows large, mobile equipment to stop, start and reverse direction without gear shifting and high-maintenance braking. LeTourneau’s wheeled loaders can load rear-dump trucks in the 85-ton to 400-ton range. Our log stackers offer two- or four-wheel drive configurations and load capacities ranging from 35 to 55 tons.

Mining products and parts are distributed through our own distribution network serving the western United States, Australia, China and Brazil as well as through a worldwide network of independent dealers. These dealers have agreements to sell our products to end-users and provide follow-up service and parts directly to those end-users. We focus on after-market parts and components for the repair and maintenance of our machines and market these items through the same dealer network. Global sites for parts stocking, rebuilding and service, including dealers, comprise approximately 45 locations on six continents.

From our mini-mill in Longview, Texas, we recycle scrap metal and produce carbon, alloy and tool steel plate products for internal needs as well as external customers. We concentrate on niche markets that require higher-end alloy steel grades, including mold steels, aircraft-quality steels and resulfurized and boron grades. Sales consist primarily of steel plate, but also include value-added fabrication of steel products. Our products are generally sold to steel service centers, fabricators and manufacturers through a direct sales force. Plate products are sold throughout North America while sales of fabricated products are more regional, encompassing Texas, Oklahoma, Louisiana, Mississippi and Arkansas. Carbon and alloy plate products are also used internally in the production of equipment and parts.

We conduct ongoing research and product development, primarily to increase the capacity and performance of our product lines on a continuous-improvement basis, and routinely evaluate our products and after-market applications for potential enhancements.

We offer warranties and parts guarantees extending for stipulated periods of ownership or hours of usage, whichever occurs first. In most cases, dealers of our products perform the warranty work. For drilling equipment, we generally perform warranty work directly and accrue for estimated future warranty costs based on historical experience.

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Raw Materials

The principal raw material used in our manufacturing operations is steel plate, much of which is supplied by our Longview mini-mill. Other required materials are generally available in sufficient quantities to meet our manufacturing needs through purchases in the open market, and we do not believe that we are dependent on any single supplier.

Competition

Since 1955, when the first LeTourneau jack-up was delivered, LeTourneau has been recognized as a leading designer and builder of jack-up drilling rigs, having designed or built approximately one-third of all jack-ups currently in operation worldwide. We believe there are currently 67 jack-ups under construction worldwide, 10 of which are LeTourneau designs. The number of competitors in jack-up rig design has grown in recent years, as well as the number of shipyard facilities to provide jack-up rig construction and repair services, and some of these competitors are significantly larger than LeTourneau.

We encounter significant competition in the drilling equipment market. The leading competitor in the mud pump market is estimated to have more than a 50% share of the market. Our shares of the top drive, drawworks, rotary table and land rig markets are not significant.

We have four major steel plate competitors. Our share of the overall steel market is small, but we are very competitive in certain niche applications for high-strength alloy, thick plate. Internal requirements for steel plate provide a base load for the steel mill.

We encounter competition worldwide from several sources in mining products. Our wheeled-loader product lines have a number of competitors except in the largest loader size. In forestry, our log stackers have four major competitors.

Our competition in the sale of after-market parts for mining and forestry products is fragmented, with only three other companies considered to be direct competitors. Vendors supplying parts directly to end users and others who obtain and copy the parts for cheaper and lower-quality substitutes provide more intense competition to us than do direct competitors.

Governmental Regulation

Our jack-up rig designs are subject to regulatory approval by various agencies, depending on the geographic areas where the rig will be qualified for drilling. Other than the approvals that classify the jack-up as a vessel, the rules relate primarily to safety and environmental issues, vary by location and are subject to frequent change.

In the United States, our manufacturing operations and facilities are subject to regulation by a variety of local, state, and federal agencies with authority over safety and environmental compliance. These include the Environmental Protection Agency (“EPA”), OSHA, and other state and local jurisdictions with comparable statutes. Internationally, our operations and facilities are subject to comparable regulations in the countries in which we operate.

We have the required permits at our manufacturing facilities for wastewater discharges, solid waste disposal and air emissions. Our manufacturing operations may generate waste products which are considered hazardous by the EPA or other governmental agencies. We properly contain and dispose of these waste products at approved waste disposal facilities. In the event we experience an unplanned release of waste products, we may be liable for damages from any air, water or land pollution that may result. We believe that our compliance with environmental protection laws and regulations will have no material effect on our capital expenditures, earnings or competitive position during 2011. Further regulations may reasonably be anticipated, but any effects on our manufacturing operations cannot be accurately predicted at this time.

As a manufacturing company, we may be responsible for certain risks associated with the use of our products. These risks include product liability claims for personal injury and/or death, property damage, loss of product use, business interruption and necessary legal expenses to defend us against such claims. We carry insurance in amounts we consider appropriate.

EMPLOYEES

At December 31, 2010, we had 5,217 employees worldwide, as compared to 4,846 and 6,023 at December 31, 2009 and 2008, respectively. None of our employees are covered by collective bargaining agreements with labor unions. We consider relations with our employees to be satisfactory.

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CUSTOMERS

One drilling customer, Saudi Aramco, accounted for 11% of consolidated revenues in 2010 and 15% in each of 2009 and 2008.

In our manufacturing operations, in 2010 one customer provided 20% of Drilling Products and Services revenues, and one customer provided 19% of Mining, Forestry, and Steel Products revenues; such amounts, however, were not material to consolidated revenues.

ITEM 1A. RISK FACTORS

You should consider carefully the following risk factors, in addition to the other information contained and incorporated by reference in this Form 10-K, before deciding to invest in our common stock.

We operate in volatile businesses that are heavily dependent upon commodity prices and other factors beyond our control.

The success of our drilling operations depends heavily upon conditions in the oil and gas industry and the level of demand for drilling services. Demand for our drilling services is vulnerable to declines that are typically associated with depressed oil and natural gas prices. Even the perceived risk of a decline in oil or natural gas prices may cause oil and gas companies to reduce their spending, in which case demand for our drilling services could decrease and our drilling revenues may be adversely affected by lower rig utilization and/or day rates. Oil and natural gas prices have historically been very volatile, and our drilling operations have in the past suffered through long periods of weak market conditions.

Demand for our drilling services also depends on additional factors that are beyond our control, including:

·	worldwide demand for drilling services

·	worldwide demand and prices for oil, natural gas and other commodities

·	the level of exploration and development expenditures by energy companies

·	the willingness and ability of the Organization of Petroleum Exporting Countries, or OPEC, to limit production levels and influence prices

·	the level of production in non-OPEC countries

·	the general economy, including inflation

·	the condition of global capital markets

·	weather and climate conditions in our principal operating areas, including possible disruption of exploration and development activities due to hurricanes and other severe weather conditions

·	environmental and other laws and regulations

·	policies of various governments regarding exploration and development of oil and natural gas reserves

·	domestic and international tax policies

·	political and military conflicts in oil-producing areas and the effects of terrorism

·	advances in exploration and development technology

·	further consolidation of our customer base

·	further consolidation of our competitors

Our drilling operations have been and will continue to be adversely affected by dramatic declines in oil and natural gas prices, as occurred in recent years, but we cannot predict such events. Nor can we assure you that a reduction in offshore drilling activity will not occur for other reasons. Our manufacturing operations are also dependent on commodity prices and financial market conditions which affect demand for rigs and related components, mining and timber equipment and after-market parts.

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The delivery of new offshore drilling rigs currently under construction may further reduce our rig utilization and day rates and could lead to impairment charges.

We believe there are 67 competitive jack-up rigs under construction worldwide as of February 25, 2011, or approximately 14% of the existing jack-up fleet. Most of these rigs do not have drilling contracts in place, and their delivery will increase the supply of available rigs competing for work, which could further reduce rig utilization and day rates. In addition, many of these rigs could enter the market at a time of excess capacity and low day rates. Prolonged periods of low rig utilization require us to accept lower day rates, or may cause us to temporarily take rigs out of service, or “stack” rigs, which would adversely affect our operating results and cash flows. We may be required to recognize impairment charges on our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that their carrying values may not be recoverable.

Our markets are highly competitive, and satisfactory price levels are difficult to maintain.

Our drilling and manufacturing markets are highly competitive, and no single participant is dominant. Drilling contracts are often awarded on a competitive-bid basis, with intense price competition frequently being the primary factor determining which qualified contractor is awarded the job. Relocation of offshore rigs from areas of lower activity, such as the U.S. Gulf of Mexico in 2009 and 2010, to more active international markets has further increased the competition among rigs looking for work in those areas. The anticipated delivery of 67 new jack-ups over the next three years and ongoing consolidation by oil and gas exploration and production companies will further increase the supply of rigs while reducing the number of available customers. This consolidation has also resulted in drilling projects being delayed. We may have to further reduce our prices in order to remain competitive, which would have an adverse effect on our operating results.

If we or our customers are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to suspend or cease our operations, and our revenues from offshore operations may be reduced.

Crude oil and natural gas exploration and production operations in the United States and the Gulf of Mexico require numerous permits and approvals for us and our customers from governmental agencies. If we or our customers are not able to obtain necessary permits and approvals, our operations will be adversely affected. Obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals, future changes to these permits or approvals, or any adverse change in the interpretation of existing permits and approvals. In addition, such regulatory requirements and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations and may create a risk of expensive delays or loss of value if a project is unable to function as planned due to changing requirements.

In 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement, issued Notices to Lessees implementing new safety regulations applicable to drilling operations in the Gulf of Mexico. These NTLs have adversely impacted the ability of our customers to obtain necessary permits and approval on a timely basis and/or to continue operations uninterrupted under existing permits. The BOEMRE subsequently issued new regulations which formalized many of the requirements set forth in the NTLs and issued additional environmental and safety requirements. We have been evaluating our own safety programs and are working with our customers to meet these requirements; however, compliance with these new regulatory requirements may result in interruption of operations, reduced revenues and higher operating costs.

We are subject to governmental laws and regulations that could cause significant costs and liability on us for environmental and natural resource damages.

Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation. In addition, the United States and other countries in which we operate have regulations relating to environmental protection and pollution control. Rowan could become liable for damages resulting from pollution of offshore waters and, under United States regulations, we must document financial responsibility. Generally, we are substantially indemnified under our drilling contracts for pollution damages, except in certain cases of pollution emanating above the surface of land or water from spills of pollutants, or pollutants emanating from our drilling rigs. We can provide no assurance, however, that such indemnification provisions can be enforced.

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We will experience reduced profitability if our customers terminate or seek to renegotiate our drilling contracts.

Some of our drilling contracts are cancelable by the customer upon specific notice, or upon the occurrence of events beyond our control, such as the loss or destruction of the rig due to weather, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. Not all of our contracts require the customer to make an early termination payment upon cancellation. Any early termination payments that may be required under our contracts may not be sufficient to fully compensate us for the loss of the contract and could result in the rig becoming idle for an extended period of time. Additionally, a customer may be able to obtain a comparable rig at a lower daily rate and seek to renegotiate the terms of its existing drilling contract with us.

Our customers may be unable to indemnify us.

Consistent with standard industry practice, we typically obtain contractual indemnification from our customers whereby they generally agree to protect and indemnify us for liabilities resulting from various hazards associated with the drilling industry. We can provide no assurance, however, that our customers will be financially able to meet these indemnification obligations. The failure of a customer to meet such obligations, the failure of one or more of our insurance providers to meet claim obligations, or losses or liabilities resulting from unindemnified, uninsured or underinsured events could have a material adverse effect on our financial position, results of operations and cash flows.

We have and will likely continue to have certain customer concentrations which increase our risks and may reduce profitability in certain situations.

The Company has certain significant customers, particularly in the Gulf of Mexico and the Middle East. The loss or material reduction of business from any such customers could have a material adverse impact on our results of operations and cash flows. Moreover, to the extent that we may be dependent on any single customer, we could be subject to the risks faced by that customer to the extent that such risks impede the customer's ability to continue operating and make timely payments to us.

Many of our drilling rigs are subject to damage or destruction by severe weather, and our business may be affected by the threat of severe weather.

Much of the Gulf of Mexico, the North Sea and offshore eastern Canada frequently experience hurricanes or other extreme weather conditions. Many of our offshore drilling rigs are located in these areas and are thus subject to potential damage or destruction by severe weather. Damage caused by high winds and turbulent seas could cause us to suspend operations on drilling rigs for significant periods of time until the damage can be repaired. Even if our drilling rigs are not damaged or lost due to severe weather, we may still experience disruptions in our operations due to damage to our customers’ platforms and other related facilities in these areas. Additionally our customers may choose not to contract our rigs for use during hurricane season, particularly our conventional rigs in the Gulf of Mexico. During Hurricanes Katrina and Rita in 2005, we lost four jack-up rigs and another was significantly damaged. During Hurricane Ike in 2008, we lost one jack-up rig. Future storms could result in the loss or damage of additional rigs, which would adversely affect our financial position, results of operations and cash flows.

Our insurance coverage for windstorms has become more expensive and may become unavailable or cost-prohibitive.

Hurricanes (or “windstorms”) have caused tremendous damage to drilling and production equipment and facilities throughout the Gulf Coast in recent years, and insurance companies have incurred substantial losses as a result. Accordingly, insurance companies have substantially reduced the levels of windstorm coverage available and have dramatically increased the price of such coverage. Coverage for potential liabilities to third parties associated with property damage and personal injuries, as well as coverage for environmental liabilities and removal of wreckage and debris associated with windstorm losses has also been limited.

As a result of the increased cost and reduced availability, we maintain windstorm physical damage coverage on only certain of our Gulf of Mexico rigs, which may differ from year to year, based on cost, location, and rig values. Currently, our windstorm physical damage coverage is subject to a $50 million per occurrence deductible with an annual aggregate limit of $150 million and covers only the Gorilla II, the EXL I and the Ralph Coffman. Our coverage for removal of wreckage is subject to a $100 million per occurrence deductible. Losses due to future windstorms not covered by insurance could

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adversely affect our financial position, results of operations and cash flows. We can provide no assurance that we will maintain future coverage at current levels.

Taxing authorities may challenge our tax positions, and we may not be able to realize expected benefits.

In 2009, we recognized certain tax benefits as a result of applying the facts of a third-party tax case to our tax situation. That case provided a more favorable tax treatment for certain foreign contracts entered into in prior years. Our income tax returns are subject to audit by U.S. federal, state, and foreign tax authorities. Taxing authorities may challenge this or any of our other tax positions. Determinations by such authorities that differ materially from our recorded estimates, favorably or unfavorably, may have a material impact on our results of operations, financial position and cash flows.

Our foreign operations typically present additional risk, and operations in certain foreign areas present higher costs.

In recent years, we have significantly expanded our operations internationally. Foreign operations are often subject to political, economic and other uncertainties not typically encountered in domestic operations, including arbitrary taxation policies, onerous customs restrictions, currency exchange fluctuations, security threats including terrorism, and the risk of asset expropriation due to foreign sovereignty over operating areas. Recent political unrest in Egypt and other Middle East countries could spread to nearby areas where we currently operate. Such unrest could potentially delay projects, either planned or currently in progress, or could impact the Company in other unforeseen ways.

With regard to the risk that our customer may terminate contracts without cause on short notice, contractually or by governmental action, we assume greater risks of such events in foreign areas, where legal protections may be less available to the Company.

Any such unforeseen events could have a material adverse effect on our financial position, results of operations and cash flows. Additionally, operations in certain foreign areas, such as the North Sea, are highly regulated and have higher compliance and operating costs in general.

Most of our contracts are fixed-price contracts, and increases in our operating costs or the impact of any general inflation could have an adverse effect on the profitability of those contracts.

Most of our drilling contracts provide for the payment of a fixed day rate during periods of operation, and reduced day rates during periods of other activities, and our manufacturing contracts typically provide for a fixed price. Many of our operating costs are unpredictable and can vary based on events beyond our control. Our gross margins will therefore vary over the terms of our contracts. If our costs increase or we encounter unforeseen costs, we may not be able to recover them from our customers, which could adversely affect our financial position, results of operations and cash flows.

High costs associated with maintaining idle rigs may cause us to experience losses, and cold-stacking rigs may result in impairment charges.

During extended periods that rigs are idle, we may choose to cold-stack our rigs. In 2010, we cold-stacked the Rowan-Juneau and the Rowan-Alaska, two of our oldest rigs. Should we cold-stack additional idle rigs, we could be exposed to additional severance costs and potential impairment charges from reductions in the fair value of our equipment.

We are subject to operating risks such as blowouts and well fires that could result in environmental damage, property loss, personal injury and death, some of which may not be covered by insurance or recoverable indemnification.

Our drilling operations are subject to many hazards that could increase the likelihood of accidents. Accidents can result in:

•

costly delays or cancellations of drilling operations;

•

serious damage to or destruction of equipment;

•

personal injury or death;

•

significant impairment of producing wells, leased properties or underground geological formations; and

•

major environmental damage.

Our offshore drilling operations are also subject to marine hazards, whether at drilling sites or while equipment is under tow, such as vessel capsizings, collisions or groundings. In addition, raising and lowering jack-up rigs and drilling into high-

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pressure formations are complex, hazardous activities, and we frequently encounter problems. Any ongoing change in weather patterns or climate could increase the adverse impact of marine hazards.

Our manufacturing processes could pollute the air, land, and inland waters, and the products we manufacture could be implicated in lawsuits alleging environmental harm, property loss, personal injury and death.

In past years, we have experienced some of the types of incidents described above, including high-pressure drilling accidents resulting in lost or damaged drilling formations and towing accidents resulting in lost drilling equipment. Any future such events could result in operating losses and have a significant adverse impact on our business.

Changes to our inventory valuation allowances may reduce our future operating results.

We recognize valuation allowances against our inventories based on historical usage of inventory on hand, assumptions about future demand based on market conditions, and estimates about potential alternative uses, which are usually limited. Our inventories generally consist of spare parts, work in process, and raw materials to support ongoing manufacturing operations and our installed base of drilling, mining and timber equipment. Customers rely on us to stock these specialized items to ensure that their equipment can be repaired and serviced in a timely manner. The estimated carrying values of our inventories are therefore indirectly affected by demand for oil, natural gas and other commodities, general economic conditions worldwide, and the potential obsolescence of various types of equipment we sell, among other factors. In early 2010, the Drilling Products and Systems manufacturing segment performed an assessment of its Houston-based raw materials and supplies inventory. As a result, the Company increased its inventory valuation reserve by approximately $42.0 million and recorded a corresponding charge to operations to reflect a reduction in the estimated realizable value of items that were deemed to be nonconforming or slow moving.

Deterioration in worldwide demand for oil, natural gas and certain other commodities, or the development of new technologies which make older drilling, mining and timber technologies obsolete, could require us to record additional reserves to reduce the value of our inventory and reduce our future operating results.

Rig upgrades, enhancements and new construction projects are subject to risks which could cause delays or cost overruns and adversely affect our financial position, results of operations and cash flows.

New drilling rigs may experience start-up complications following delivery or other unexpected operational problems that could result in significant uncompensated downtime, reduced day rates or the cancellation or termination of drilling contracts. Rig construction projects are subject to risks of delay or cost overruns inherent in any large construction project from numerous factors, including the following:

•

shortages of equipment, materials or skilled labor;

•

unscheduled delays in the delivery of ordered materials and equipment or shipyard construction;

•

failure of equipment to meet quality and/or performance standards;

•

financial or operating difficulties of equipment vendors or the shipyard;

•

unanticipated actual or purported change orders;

•

inability to obtain required permits or approvals;

•

unanticipated cost increases between order and delivery, which can be up to two years;

•

adverse weather conditions and other events of force majeure;

•

design or engineering changes; and

•

work stoppages and other labor disputes.

Significant cost overruns or delays could adversely affect our financial position, results of operations and cash flows. Additionally, failure to complete a project on time may result in the delay or loss of revenue from that rig, which also could adversely affect our financial position, results of operations and cash flows.

Regulation of greenhouse gases and climate change could have a negative impact on our business.

Some scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”) and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. Legislative and regulatory measures to address

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concerns that emissions of GHGs are contributing to climate change are in various phases of discussions or implementation at the international, national, regional and state levels.

In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which established emission targets for GHGs, became binding on the countries that had ratified it. We have recently operated offshore eastern Canada, which is one of the countries that ratified the Kyoto Protocol. International discussions are underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012.

In the United States, federal legislation imposing restrictions on GHGs is under consideration. Proposed legislation has been introduced that would establish an economy-wide cap on emissions of GHGs and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions. In addition, the EPA is taking steps that would result in the regulation of GHGs as pollutants under the Clean Air Act (“CAA”). To date, the EPA has issued (i) a “Mandatory Reporting of Greenhouse Gases” final rule, effective December 29, 2009, which establishes a new comprehensive scheme requiring operators of stationary sources in the United States emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually; and (ii) an "Endangerment Finding" final rule, effective January 14, 2010, which states that current and projected concentrations of six key GHGs in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, allowing the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crude oil). Finally, according to the EPA, the final motor vehicle GHG standards will trigger construction and operating permit requirements for stationary sources. As a result, the EPA has proposed to tailor these programs such that only large stationary sources will be required to have air permits that authorize GHG emissions.

Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have an adverse impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have an adverse impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and/or result in a disruption of our customer's operations.

Also, on June 26, 2009, the U.S. House of Representatives passed “American Clean Energy and Security Act of 2009” or ACESA, which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of “greenhouse gases.” The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions, and the Obama Administration has indicated its support of legislation to reduce greenhouse gas emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, the adoption and implementation of any CAA regulations, and any future federal, state or local laws or implementing regulations that may be adopted to address greenhouse gas emissions, could require us to incur increased operating costs and could adversely affect demand for oil and natural gas and our services. The effect on our operations could include increased costs to operate and maintain our equipment and facilities, install new emission controls on our equipment or facilities, measure and report our emissions, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.

Anti-takeover provisions in our Certificate of Incorporation and bylaws could make it difficult for holders of our common stock to receive a premium for their shares upon a change of control.

Holders of the common stock of acquisition targets may receive a premium for their shares upon a change of control. Delaware law and the following provisions, among others, of our Certificate of Incorporation and bylaws could have the effect of delaying or preventing a change of control and could prevent holders of our common stock from receiving such a premium:

•

Special meetings of stockholders may not be called by anyone other than our board of directors, our chairman, our executive committee or our president or chief executive officer.

•

Our board of directors is divided into three classes whose terms end in successive years, so that less than a majority of our board comes up for election at any annual meeting.

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•

Our board of directors has the authority to issue up to 5,000,000 shares of preferred stock and to determine the voting rights and other privileges of these shares without any vote or action by our stockholders.

Three of our Super Gorilla class rigs and two of our Tarzan Class rigs are pledged as security under our government-guaranteed debt arrangements.

If operating conditions deteriorate and if market conditions were to remain depressed for a long period of time, our results of operations would suffer, and working capital and other financial resources may not be available or adequate to service our outstanding debt. Three of our Super Gorilla class jack-ups and two of our Tarzan Class jack-ups are pledged as security under our government-guaranteed debt arrangements. If we were unable to service our debt, it is possible that these assets could be removed from our fleet, in which case our ability to generate sufficient revenues and cash flows would be significantly reduced.

One of our rigs under construction does not yet have a drilling commitment.

We have not yet obtained a drilling commitment for one of our three rigs under construction. Failure to secure an economical contract prior to delivery could negatively impact our operating results.

ITEM 1B. UNRESOLVED STAFF COMMENTS

The Company has no unresolved Securities and Exchange Commission staff comments.

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ITEM 2. PROPERTIES

Rowan leases as its corporate headquarters approximately 79,000 square feet of space in an office tower located at 2800 Post Oak Boulevard in Houston, Texas.

DRILLING RIGS

Following are summaries of the principal drilling equipment owned by the Company and location at February 25, 2011.

Offshore Rigs


			Depth (feet)(2)
Rig Name	Class Number(1)	Class Name/Type(1)	Water	Drilling	Year in Service	Location

Rigs under construction (High-Specification Jack-ups): (3)
Rowan EXL IV	S116E	EXL	350	35,000	2011	Shipyard
Joe Douglas	240C	240C	400	35,000	2011	Shipyard
Rowan Norway	-	N-Class	450	35,000	2011	Shipyard

High-Specification Jack-ups: (3)
Rowan Stavanger	-	N-Class	450	35,000	2011	North Sea
Rowan Viking	-	N-Class	450	35,000	2010	North Sea
Rowan EXL III	S116E	EXL	350	35,000	2010	Gulf of Mexico
Rowan EXL II	S116E	EXL	350	35,000	2010	Trinidad
Rowan EXL I	S116E	EXL	350	35,000	2010	Gulf of Mexico
Ralph Coffman (4)	240C	240C	400	35,000	2009	Gulf of Mexico
Rowan-Mississippi (4)	240C	240C	375	35,000	2008	Gulf of Mexico
J.P. Bussell (4)	225C	Tarzan	300	35,000	2008	Egypt
Hank Boswell (4)	225C	Tarzan	300	35,000	2006	Middle East
Bob Keller (4)	225C	Tarzan	300	35,000	2005	Middle East
Scooter Yeargain (4)	225C	Tarzan	300	35,000	2004	Middle East
Bob Palmer (4)	224C	Super Gorilla XL	550	35,000	2003	Middle East
Rowan Gorilla VII (5)	219C	Super Gorilla	400	35,000	2002	North Sea
Rowan Gorilla VI (5)	219C	Super Gorilla	400	35,000	2000	North Sea
Rowan Gorilla V (5)	219C	Super Gorilla	400	35,000	1998	North Sea
Rowan Gorilla IV (4)	200C	Gorilla	450	35,000	1986	Mexico

Premium Jack-ups: (6)
Rowan Gorilla III (4)	200C	Gorilla	450	30,000	1984	Gulf of Mexico
Rowan Gorilla II (4)	200C	Gorilla	450	30,000	1984	Gulf of Mexico
Rowan-California (4)	116C	116C	300	30,000	1983	Middle East
Cecil Provine (4)	116C	116C	300	30,000	1982	Gulf of Mexico
Gilbert Rowe (4)	116C	116C	350	30,000	1981	Middle East
Arch Rowan (4)	116C	116C	350	30,000	1981	Middle East
Charles Rowan (4)	116C	116C	350	30,000	1981	Middle East
Rowan-Paris (4)	116C	116C	350	30,000	1980	Middle East
Rowan-Middletown (4)	116C	116C	350	30,000	1980	Middle East

Conventional Jack-ups: (7)
Rowan-Juneau	116	Slot	250	30,000	1977	Gulf of Mexico
Rowan-Alaska	84	Slot	350	30,000	1975	Gulf of Mexico
Rowan-Louisiana	84	Slot	350	30,000	1975/2006 (8)	Gulf of Mexico

____________

(1)	Class number is assigned by LeTourneau and denotes the design and construction. Class name is assigned by Rowan. The Gorilla class unit is designed for extreme hostile environments. The Super Gorilla class unit is an enhanced version of the Gorilla class, and the Super Gorilla XL class unit is an enhanced version of the Super Gorilla class. The 240C is LeTourneau’s latest rig design. The EXL class unit is an enhanced version of the 116C. The N-Class is designed for operation in the highly regulated Norwegian sector of the North Sea and can be equipped to perform drilling and production operations simultaneously. All rigs are equipped with top-drive drilling systems.
(2)	Indicates rated water depth in current location and rated drilling depth.
(3)	High-specification rigs are those that have hook-load capacity of at least two million pounds.
(4)	Unit is equipped with three mud pumps.
(5)	Unit is equipped with four mud pumps.
(6)	Premium jack-ups are cantilevered rigs capable of operating in water depths of 300 feet or more.
(7)	Units are equipped with a skid-off capability. For a discussion of skid-off technology, refer to “Offshore Operations” in Item 1, Business, of this Form 10-K.
(8)	The Rowan-Louisiana was damaged during Hurricane Katrina in 2005 and was substantially refurbished in 2006.

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Onshore Rigs

		Maximum
		Drilling	Maximum
Rig Name (1)	Type	Depth (feet)	Horsepower	Location

Rig 9	Diesel electric	20,000	2,000	Louisiana
Rig 12	SCR diesel electric	18,000	1,500	Texas
Rig 14	AC electric	35,000	3,000	Louisiana
Rig 15	AC electric	35,000	3,000	Texas
Rig 26	SCR diesel electric	25,000	2,000	Texas
Rig 29	Mechanical	18,000	1,500	Texas
Rig 30	AC electric	20,000	2,000	Louisiana
Rig 31	SCR diesel electric	35,000	3,000	Texas
Rig 33	SCR diesel electric	18,000	1,500	Texas
Rig 35	SCR diesel electric	18,000	1,500	Texas
Rig 51	SCR diesel electric	25,000	2,000	Louisiana
Rig 52	SCR diesel electric	25,000	2,000	Texas
Rig 53	SCR diesel electric	25,000	2,000	Louisiana
Rig 54	SCR diesel electric	25,000	2,000	Louisiana
Rig 59	AC electric	25,000	2,000	Louisiana
Rig 60	AC electric	25,000	2,000	Oklahoma
Rig 61	AC electric	25,000	2,000	Texas
Rig 62	AC electric	25,000	2,000	Oklahoma
Rig 63	AC electric	25,000	2,000	Texas
Rig 64	AC electric	25,000	2,000	Texas
Rig 65	AC electric	25,000	2,000	Louisiana
Rig 66	AC electric	25,000	2,000	Texas
Rig 67	AC electric	25,000	2,000	Texas
Rig 68	AC electric	25,000	2,000	Alaska
Rig 76	AC electric	25,000	2,000	Texas
Rig 77	AC electric	25,000	2,000	Texas
Rig 84	AC electric	25,000	2,000	Texas
Rig 85	AC electric	25,000	2,000	Alabama
Rig 86	AC electric	25,000	2,000	Texas
Rig 87	AC electric	25,000	2,000	Texas

____________

(1)	All but Rig 29 are equipped with top-drive drilling systems.

Rowan’s drilling division leases and, in some cases, owns various operating and administrative facilities generally consisting of office, maintenance and storage space in the United States in Texas and Alaska and in Canada, Scotland, Saudi Arabia, Qatar, Egypt, Trinidad, Norway and Mexico.

MANUFACTURING FACILITIES

LeTourneau’s principal manufacturing facility is located in Longview, Texas, on approximately 2,400 acres with approximately 1.2 million square feet of covered working area. The facility is owned and contains:

•

a steel mini-mill with 330,000 square feet of covered working area;

•

a fabrication shop with 300,000 square feet of covered working area;

•

a machine shop with 140,000 square feet of covered working area; and

•

an assembly shop with 124,000 square feet of covered working area.

The mini-mill has two 25-ton electric arc furnaces capable of producing 120,000 melted tons per year.

LeTourneau leases approximately 22,000 square feet of office space in Houston, Texas, for its corporate headquarters. We machine, fabricate, assemble, and test drilling products and systems at a facility we own in Houston, which is adjacent to LeTourneau’s leased headquarters, and has approximately 450,000 square feet of covered work area and 45,000 square feet of additional office space. This capacity is supported by the Longview, Texas, facility. Additionally, we lease warehouse and administrative facilities in Texas, Louisiana and Canada.

We also own a jack-up rig construction facility located in Vicksburg, Mississippi, on 1,850 acres of land that has approximately 560,000 square feet of covered work area. It is possible we may have excess capacity at our Vicksburg facility later in 2011, following completion of a rig construction project, at which time we may decide to use the facility for other purposes or explore other options. Our rig service and repair operation is carried out primarily at our Sabine Pass, Texas, facility.

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Our distributor of forestry products in the northwestern United States is located on a six-acre site in Troutdale, Oregon, with approximately 22,000 square feet of building space.

Our distributor of mining products in the western United States is located in a leased facility in Tucson, Arizona, having approximately 20,000 square feet. Our distributor of mining products in Australia is located in a leased facility in Murarrie, Queensland, having approximately 29,500 square feet. There are additional branch locations in each Australian territory. Our distributor of mining products in Brazil leases an office building and warehouse.

ITEM 3. LEGAL PROCEEDINGS

Reference should be made to Note 7 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K for the status of significant legal proceedings.

EXECUTIVE OFFICERS OF THE REGISTRANT

The names, positions and ages of the officers of the Company as of March 1, 2011, are listed below. Officers are appointed by the Board of Directors and serve at the discretion of the Board of Directors. There are no family relationships among these officers, nor any arrangements or understandings between any officer and any other person pursuant to which the officer was selected.

Name	Position	Age

W. Matt Ralls	President and Chief Executive Officer	61
John L. Buvens	Executive Vice President, Legal	55
Mark A. Keller	Executive Vice President, Business Development	58
David P. Russell	Executive Vice President, Drilling Operations	49
J. Kevin Bartol	Senior Vice President, Corporate Development	51
William H. Wells	Senior Vice President, Chief Financial Officer and Treasurer	48
Barbara A. Carroll	Vice President, Health, Safety and Environment	56
Michael J. Dowdy	Vice President, Engineering	51
Lisa Gauthier	Vice President and Chief Information Officer	41
Gregory M. Hatfield	Vice President and Controller	41
Melanie M. Trent	Vice President and Corporate Secretary	46
Terry D. Woodall	Vice President, Human Resources	62
George C. Jones	Compliance Officer	45
Thomas P. Burke	President and Chief Executive Officer, LeTourneau Technologies, Inc.	44

Since January 2009, Mr. Ralls’ principal occupation has been President and Chief Executive Officer. From June 2005 until his retirement in November 2007, Mr. Ralls served as Executive Vice President and Chief Operating Officer of GlobalSantaFe Corporation. Prior to that time, he served as Senior Vice President and Chief Financial Officer of GlobalSantaFe Corporation. Mr. Ralls also serves on the Board of Complete Production Services, Inc.

Since January 2007, Mr. Buvens’ principal occupation has been Executive Vice President, Legal. Prior to that time, he served as Senior Vice President, Legal.

Since January 2007, Mr. Keller’s principal occupation has been Executive Vice President, Business Development. Prior to that time, he served as Senior Vice President, Marketing.

Since January 2007, Mr. Russell’s principal occupation has been Executive Vice President, Drilling Operations. From January 2005 to January 2007, Mr. Russell served as Vice President, Drilling.

Mr. Bartol became Senior Vice President, Corporate Development in March 2010. From June 2007 to March 2010, he served as Vice President, Strategic Planning, and from January 2007 to June 2007, he was a consultant to the Company on strategic initiatives. Prior to August 2006, Mr. Bartol was Chief Financial Officer of Jindal United Steel Corporation.

Mr. Wells became Senior Vice President, Chief Financial Officer and Treasurer in March 2010. From January 2007 until March 2010, he served as Vice President, Finance, and Chief Financial Officer. From May 2005 to January 2007, he served as Vice President, Finance, and Treasurer.

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Since May 2008, Ms. Carroll’s principal occupation has been Vice President, Health, Safety and Environment. From October 2007 to May 2008, Ms. Carroll served as Vice President, Environmental Affairs. From July 2006 to October 2007, Ms. Carroll served as a consultant to the Company. Prior to that time, Ms. Carroll was Vice President of Environmental, Health and Safety for TEPPCO Partners, LLP.

Since April 2006, Mr. Dowdy’s principal occupation has been Vice President, Engineering. Prior to that time, Mr. Dowdy was Chief Engineer, Marine Group, for LeTourneau.

Ms. Gauthier became Vice President and Chief Information Officer in March 2010, after serving as Director of Information Technology from April 2008 to March 2010. Prior to that time, Ms. Gauthier was Senior Manager, Technology Services, for CapGemini.

Mr. Hatfield became Vice President and Controller in March 2010. From May 2005 to March 2010, he served as Controller.

Ms. Trent became Vice President and Corporate Secretary in March 2010. From January 2009 to March 2010, she was Corporate Secretary. From January 2007 to January 2009, Ms. Trent served as Corporate Secretary and Special Assistant to the CEO. Prior to that time, she served as Corporate Secretary and Compliance Officer.

Mr. Woodall has been Vice President, Human Resources, since joining the Company in July 2005.

Mr. Jones’ principal occupation has been Compliance Officer since July 2007. From July 2006 to July 2007, he served as Senior Corporate Counsel. Prior to that time, Mr. Jones practiced corporate law at Andrews Kurth LLP.

Mr. Burke joined the Company in December 2009 and has served as President and Chief Executive Officer of LeTourneau since January 2010. Prior to that time, he was employed by Complete Production Services, Inc., an oilfield services company, as Division President from 2006 to 2009.

PART II

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

Rowan’s common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “RDC.” The following table sets forth the high and low sales prices of our common stock for each quarterly period within the two most recent years as reported by the NYSE Consolidated Transaction Reporting System.

	2010				2009
Quarter	High		Low		High		Low
First	$	29.40	$	21.21	$	18.52	$	10.28
Second		32.82		21.66		23.90		11.40
Third		31.24		20.44		24.31		16.96
Fourth		35.39		29.23		27.54		21.42

On January 31, 2011, there were 1,571 stockholders of record.

The Company last paid a cash dividend in November 2008, and there are no current plans for dividend payments. Future dividends, if any, will only be paid at the discretion of the Board of Directors. At December 31, 2010, approximately $427 million was available for distribution to stockholders under the most restrictive provisions of the Company’s debt agreements.

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The graph below presents the relative investment performance of Rowan’s common stock, the Dow Jones U.S. Oil Equipment and Services Index, and the S&P 500 Index for the five-year period ending December 31, 2010, assuming reinvestment of dividends.

	12/31/2005		12/31/2006		12/31/2007		12/31/2008		12/31/2009		12/31/2010

Rowan Companies, Inc.		100.00		94.41		113.43		46.35		66.00		101.78
S&P 500 Index		100.00		115.80		122.16		76.96		97.33		111.99
Dow Jones US Oil Equipment & Services Index		100.00		113.47		164.47		66.94		110.56		140.78

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Issuer Purchases of Equity Securities

The following table summarizes acquisitions of our common stock for the fourth quarter of 2010:

Period	Total number of shares purchased 1		Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs 2		Maximum number of shares that may yet be purchased under the plans or programs

Month ended Oct. 31, 2010		88	$	30.16		-		1,524,600
Month ended Nov. 30, 2010		66	$	30.45		-		1,524,600
Month ended Dec. 31, 2010		24,782	$	30.90		-		1,524,600
Total		24,936	$	30.90		-

1 The total number of shares purchased includes (i) shares purchased, if any, pursuant to a publicly announced program described in footnote 2 below and (ii) shares withheld by us to satisfy tax withholding obligations in connection with stock-based compensation issued to employees. All shares acquired during the quarter ended December 31, 2010, were in connection with stock-based compensation.

2 In 1998, we announced that our Board of Directors authorized us to purchase up to eight million shares of our common stock. We last purchased shares under this program in 2002 and have no plans to purchase additional shares at the present time.

For information concerning our common stock to be issued in connection with our equity compensation plans, see Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” of this Form 10-K.

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ITEM 6. SELECTED FINANCIAL DATA

Selected financial data for each of the last five years is presented below (in thousands, except per share amounts and ratios):

	2010			2009			2008			2007			2006

Operations
Revenues:
Drilling services	$	1,208,766		$	1,214,896		$	1,451,623		$	1,382,571		$	1,067,448
Manufacturing sales and services		610,441			555,284			761,113			712,450			443,286
Total		1,819,207			1,770,180			2,212,736			2,095,021			1,510,734
Costs and expenses:
Drilling services (excluding items shown below)		553,906			525,157			629,795			591,412			504,873
Manufacturing sales and services (excluding items shown below)		512,384			475,553			624,815			596,541			372,219
Depreciation and amortization		186,563			171,445			141,395			118,796			89,971
Selling, general and administrative		132,586			102,760			115,226			94,905			78,243
Loss (gain) on disposals of property and equipment		788			(5,748	)		(30,701	)		(40,506	)		(29,266	)
Material charges and other operating expenses (1)		42,024			-			111,171			-			9,000
Gain on hurricane-related events		-			-			(37,088	)		-			-
Total		1,428,251			1,269,167			1,554,613			1,361,148			1,025,040
Income from operations		390,956			501,013			658,123			733,873			485,694
Other income (expense) — net		(11,939	)		78			(4,032	)		5,213			7,660
Income from continuing operations, before income taxes		379,017			501,091			654,091			739,086			493,354
Provision for income taxes		99,022			133,587			226,463			255,286			176,377
Income from continuing operations		279,995			367,504			427,628			483,800			316,977
Income from discontinued operations, net of taxes (2)		-			-			-			-			1,269
Net income	$	279,995		$	367,504		$	427,628		$	483,800		$	318,246
Basic income per common share:
Income from continuing operations	$	2.39		$	3.24		$	3.80		$	4.36		$	2.87
Income from discontinued operations		-			-			-			-			0.01
Net income	$	2.39		$	3.24		$	3.80		$	4.36		$	2.88
Diluted income per common share:
Income from continuing operations	$	2.36		$	3.24		$	3.77		$	4.31		$	2.84
Income from discontinued operations		-			-			-			-			0.01
Net income	$	2.36		$	3.24		$	3.77		$	4.31		$	2.85

Financial Position
Cash and cash equivalents	$	437,479		$	639,681		$	222,428		$	284,458		$	258,041
Property, plant and equipment — net	$	4,793,437		$	3,579,485		$	3,147,528		$	2,487,811		$	2,133,226
Total assets	$	6,217,457		$	5,210,694		$	4,548,892		$	3,875,305		$	3,435,398
Long-term debt, less current portion	$	1,133,745		$	787,490		$	355,560		$	420,482		$	485,404
Stockholders’ equity	$	3,752,310		$	3,110,370		$	2,659,816		$	2,348,438		$	1,874,046

Statistical Information
Current ratio		2.50			2.73			1.84			2.63			2.13
Long-term debt/total capitalization		0.23			0.20			0.12			0.15			0.21
Book value per share of common stock outstanding	$	29.71		$	27.31		$	23.51		$	21.10		$	16.97
Price range of common stock:
High	$	35.39		$	27.54		$	47.94		$	46.16		$	48.15
Low	$	20.44		$	10.28		$	12.00		$	29.48		$	29.03
Cash dividends per share	$	-		$	-		$	0.40		$	0.40		$	0.55

___________________

(1)	Material charges and other operating expenses in 2010 consisted of a $42.0 million inventory valuation charge. (See further discussion under “Inventories” in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.) The 2008 amount consisted of $62.4 million of inventory valuation charges, a $13.6 million charge for goodwill impairment, $12.7 million for professional fees related to the suspended LeTourneau monetization, an $11.8 million impairment charge due to the cancellation of the fourth 240C jack-up rig and $10.7 million for severance payments. The 2006 amount reflected an accrual for payments made in 2007 related to a Department of Justice investigation.

(2)	Income from discontinued operations in 2006 consisted of a refund of excise taxes related to the Company’s aviation operations, which were sold in 2004.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SUMMARY

Our 2010 drilling operating results benefited from offshore fleet additions and improved land activity levels, the effects of which substantially offset the impact of our concluding several peak day rate contracts during the year and lower utilization of our less capable rigs, resulting in a slight decline in drilling revenues from 2009. These factors, however, also caused an increase in operating expenses between periods, which reduced operating margins.

We were successful throughout the year in both maintaining a high level of utilization for our higher specification rigs and in obtaining contractual commitments for our newly constructed high-spec jack-ups prior to delivery, as oil and gas companies have increasingly sought more capable equipment to meet ever more demanding drilling requirements. Our less capable rigs, on the other hand, have encountered much more competition for the relatively fewer available assignments, resulting in extended periods of idle time. This segmentation of demand based on rig capability has been an emerging trend over the past two years, and one that we believe will continue. All but one of our sixteen high-spec jack-ups were under drilling contracts or commitments at February 25, 2011, as were two of our three high-spec rigs under construction, whereas only seven of our remaining twelve offshore rigs were contracted at that date.

In September 2010, we completed the acquisition of Skeie Drilling & Production ASA “SKDP,” a Norwegian entity that owned and managed the construction of three high-spec jack-up rigs. The Rowan Viking was delivered in October 2010 and is scheduled to commence operations in late March 2011 under a 19-month assignment in the UK sector of the North Sea after completion of contractually required modifications. The Rowan Stavanger was delivered in January 2011 and is expected to commence operations in the second quarter of 2011 for up to 150 days of accommodation work in the Norwegian sector, followed by an approximately 10-month drilling commitment for four wells beginning in late 2011 for work in the UK and Norwegian sectors of the North Sea. The Rowan Norway is expected to be delivered in June 2011 and has a 240-day contract for work in the UK sector of the North Sea beginning in late 2011, plus a one-year priced option.

As of February 25, 2011, we had ten offshore rigs in the Middle East, ten in the U.S. Gulf of Mexico, five in or en route to the North Sea, one each in Mexico, Trinidad and Egypt, and three under construction. At that date, fifteen of our offshore rigs had drilling contracts estimated to complete in 2011, three had contracts or commitments estimated to complete in 2012, one had a contract estimated to complete in 2013, three had contracts estimated to complete in 2014, and six were available.

Additionally, at February 25, 2011, we had 30 land rigs located in Texas, Louisiana, Oklahoma, Alabama and Alaska, 24 of which were under contract with estimated completion dates as follows: sixteen in 2011, six in 2012, and one each in 2014 and 2015.

A key element of our strategy has been to separate our manufacturing and land drilling operations from our core offshore drilling business when market conditions were suitable. We believe conditions are suitable now and expect to begin a process in 2011 to sell or spin off these businesses.

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RESULTS OF OPERATIONS

The following table highlights Rowan’s operating results by business segment (in millions):

	2010			2009		2008
Revenues:
Drilling services	$	1,208.8		$	1,214.9	$	1,451.6
Manufacturing sales and services:
Drilling products and systems		310.3			369.4		493.5
Mining, forestry and steel products		300.1			185.9		267.6
Total manufacturing sales and services		610.4			555.3		761.1
Total revenues	$	1,819.2		$	1,770.2	$	2,212.7

Costs and expenses:
Drilling services	$	809.8		$	742.8	$	781.5
Manufacturing sales and services:
Drilling products and systems		383.3			366.0		538.1
Mining, forestry and steel products		235.1			160.4		235.0
Total manufacturing sales and services		618.4			526.4		773.1
Total costs and expenses	$	1,428.2		$	1,269.2	$	1,554.6

Operating income:
Drilling services	$	399.0		$	472.1	$	670.1
Manufacturing sales and services:
Drilling products and systems		(73.0	)		3.4		(44.6	)
Mining, forestry and steel products		65.0			25.5		32.6
Total manufacturing sales and services		(8.0	)		28.9		(12.0	)
Total operating income	$	391.0		$	501.0	$	658.1

Net income	$	280.0		$	367.5	$	427.6

Rowan’s results of operations are primarily driven by the performance of our Drilling Services segment, which comprises about 95% of our fixed assets and over the past three years has generated two-thirds of our consolidated revenues and over 90% of operating income.

Costs and expenses in 2010 and 2008 included $42.0 million and $111.2 million, respectively, of certain items, which are discussed more fully in the detailed discussion of results of operations which follows.

Added (deducted) from operating income to arrive at net income were the following (in millions):

	2010			2009			2008

Interest income	$	1.5		$	1.2		$	6.3
Interest expense, net of interest capitalized		(24.9	)		(8.0	)		(1.2	)
Gain on debt extinguishment		5.3			-			-
Other income (expense) - net		6.1			6.9			(9.1	)
Provision for income taxes		(99.0	)		(133.6	)		(226.5	)

The increase in 2010 interest expense, net of interest capitalized, resulted from additional borrowings in 2009 and 2010 to finance our newbuild construction program and to refinance debt assumed in the SKDP acquisition. The gain on debt extinguishment in 2010 was attributable to the redemption of the assumed SKDP debt. See “Liquidity and Capital Resources – Financing Activities” for further discussion.

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Historically, we have conducted our foreign operations through U.S. subsidiaries, which resulted in income tax at or near the U.S. statutory rate of 35%. In late 2009, we began operating many of our foreign-based rigs through our international subsidiaries, and we have asserted that such earnings are permanently reinvested abroad. As a result, we lowered our effective tax rate to 26.1% in 2010 as compared to 26.7% in 2009 and 34.6% in 2008.

The reduced rate in 2009 compared to 2008 included the effect of operating rigs in our international subsidiaries for a part of 2009 and the effect of applying the facts of a third-party tax case to our tax situation. That case provided a more favorable tax treatment for certain foreign contracts entered into in prior years. The reduced rate in 2010 was attributable to moving certain other rigs into our international subsidiaries and to having a greater proportion of income in lower-tax jurisdictions. The full year impact of rig movements completed in 2010 combined with the startup of additional foreign-owned rigs should lower our effective tax rate to the upper teens in 2011.

The performance of each of our operating segments over the period from 2008 through 2010 is discussed more fully below.

Drilling Services

Drilling Services’ operating results are primarily a function of rig utilization and day rates achieved by our land and offshore rig fleets. Utilization and day rates are primarily determined by the level of oil and gas exploration and development expenditures, which are heavily influenced by trends in oil and natural gas prices, and the availability of competitive equipment. When drilling markets are strengthening, day rates generally lag the upward trend in rig utilization, and day rate increases can be more significant as utilization approaches 90% or more. When drilling markets are weakening, contractors often reduce day rates in an effort to maintain utilization. Both rig utilization and day rates have historically declined much faster than they have risen.

Our Rig Fleets

Our offshore fleet currently consists of 28 jack-up rigs, featuring:

·	Two N-Class jack-ups delivered in October 2010 and January 2011,

·	Three EXL-class jack-ups delivered from May through December 2010,

·	Two 240C class jack-ups, delivered in 2008 and 2009, respectively,

·	Four Tarzan Class jack-ups delivered from 2004 through 2008,

·	Four Super Gorilla class jack-ups delivered from 1998 through 2003,

·	Three Gorilla class jack-ups built during the early 1980s,

·	Seven 116C class jack-ups built during the early 1980s, and

·	Two 84 class jack-ups and one 116 class jack-up built during the mid-to-late 1970s.

Sixteen of the twenty-eight rigs in our jack-up fleet have at least two million pounds of hook-load capability, which enables efficient drilling beyond 30,000 feet. We consider such rigs to be “high-specification” rigs, which include the N-Class, EXL-Class, 240Cs, Tarzan Class, Super Gorillas and one of the Gorilla class rigs.

We have three additional high-specification jack-ups under construction – the N-Class Rowan Norway, the 240C-Class Joe Douglas, and the EXL IV – with expected deliveries from mid to late 2011. See further discussion of our offshore newbuild program under “Liquidity and Capital Resources – Investing Activities.”

In addition to our offshore fleet, we own a fleet of 30 land rigs, including 16 rigs constructed since 2005, four rigs built from 2001 through 2002, and ten older rigs that have been refurbished over the years.

Current Operations and Markets

Worldwide rig demand is inherently volatile and has historically varied among geographic markets, as has the supply of competitive equipment. Exploration and development expenditures can be impacted by many local factors, such as political and regulatory policies, seasonal weather patterns, lease expirations, new oil and gas discoveries and reservoir depletion. Over time, the level and expected direction of oil and natural gas prices are the principal determinants of drilling activity, and oil and gas prices are ultimately a function of the supply of and demand for those commodities.

Our primary drilling markets are currently the U.S. Gulf of Mexico (“US GOM”), the Middle East, and the North Sea. We also have single rigs located in Mexico, Trinidad and Egypt.

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The US GOM offshore drilling market is highly fragmented among several oil and gas companies, many of which are independent operators whose drilling activities may be highly dependent on near-term operating cash flows. A typical drilling assignment may call for 60 days of exploration or development work performed under a single-well contract with negotiable renewal options. Long-term contracts have been relatively rare, and generally are available only from the major integrated oil companies and a few of the larger independent operators. Drilling activity and day rates in the US GOM have tended to fluctuate rather quickly, and generally follow trends in natural gas prices. Offshore drilling demand in the shallower waters of the US GOM has been weak over the last few years as a result of low natural gas prices. In 2010, the market slowed further as a result of the fallout from the Deepwater Horizon incident in April 2010 and the delayed permitting process that followed (see further discussion under “Drilling Services – Outlook”). As of February 25, 2011, industry utilization in the US GOM was 42%. We currently have ten rigs in the US GOM – six under contracts expiring in 2011, one commitment expiring in 2012 and two that are idle. One of the rigs under contract, the Ralph Coffman, is scheduled to begin mobilizing to the Middle East for a three-year contract to commence in the third quarter of 2011.

International markets present more opportunities for longer-term drilling contracts and high-specification rigs than do domestic markets. The relocation of rigs from domestic to foreign markets is a significant undertaking, and often interrupts revenues and cash flows for up to five months, particularly when equipment upgrades are involved. Thus, major relocations are typically carried out only when the likelihood of higher long-term returns heavily outweighs the short-term costs.

The Middle East has been a primary focus among our international operations in recent years. We currently have three rigs operating in Saudi Arabia, three rigs operating in Qatar, and one in a shipyard in Bahrain undergoing modifications for a contract in Saudi Arabia (see also “Drilling – Outlook” for further discussion). Three additional rigs are located in a shipyard in Dubai. As of February 25, 2011, industry utilization in the Middle East was 72%. Six of our ten rigs there have contracts expiring in 2011, two rigs (including the Ralph Coffman) have contracts expiring in 2014 and three rigs are idle.

The North Sea is a mature, harsh-environment offshore drilling market that has long been dominated by major oil and gas companies operating within a relatively tight regulatory environment. Project lead times are often lengthy, and drilling assignments, which typically require ultra premium equipment capable of handling extreme weather conditions and high down-hole pressures and temperatures, can range from several months to several years. Thus, drilling activity and day rates in the North Sea move slowly in response to market conditions, and generally follow trends in oil prices. As of February 25, 2011, industry utilization in the North Sea was 87%. We currently have five rigs located in or en route to the North Sea, with contracts or commitments expiring from 2011 through 2013.

Our remaining rigs outside the U.S. are the Rowan Gorilla IV, which is operating in the Gulf of Mexico under a contract that is expected to conclude in the third quarter of 2011, and the EXL II, which began a three-year contract for work in Trinidad in early 2011. The J.P. Bussell recently completed work offshore Egypt and is currently available.

In addition to our offshore rigs, at February 25, 2011, we had eighteen land rigs in Texas, eight in Louisiana, two in Oklahoma and one each in Alabama and Alaska, of which 24 were operating under contracts ranging from less than one to four years.

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2010 Compared to 2009

The following table highlights the performance of our Drilling Services segment during 2010 compared to 2009 (dollars in millions, except day rates):

	2010						2009
	Amount			% of Revenues			Amount			% of Revenues

Revenues	$	1,208.8			100	%	$	1,214.9			100	%
Operating costs		(554.0	)		-46	%		(525.2	)		-43	%
Depreciation expense		(170.2	)		-14	%		(155.9	)		-13	%
Selling, general and administrative expenses		(85.0	)		-7	%		(68.0	)		-6	%
(Loss) gain on property disposals		(0.6	)		0	%		6.3			1	%
Operating income	$	399.0			33	%	$	472.1			39	%

Offshore fleet:
Average day rate	$	162,300					$	175,100
Revenue-producing days		6,162						5,876
Available rig days		8,614						8,030
Rig utilization		72	%					73	%

Land fleet:
Average day rate	$	20,600					$	23,200
Revenue-producing days		8,947						7,175
Available rig days		11,312						11,503
Rig utilization		79	%					62	%

The following table summarizes average prices for oil and natural gas and our utilization and average day rates by quarter in 2010, and for the full years 2010 and 2009 for our offshore fleet:

	Oil (per bbl) *		Natural gas (per MCF) *		Average utilization			Average day rate
2010:
First quarter	$	78.81	$	4.99		75	%	$	183,200
Second quarter	$	77.82	$	4.35		75	%	$	174,500
Third quarter	$	76.06	$	4.24		72	%	$	147,300
Fourth quarter	$	85.16	$	3.98		65	%	$	142,500
Full year:
2010	$	79.48	$	4.38		72	%	$	162,300
2009	$	61.95	$	4.16		73	%	$	175,100

__________

*	Source: New York Mercantile Exchange (NYMEX)

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Drilling revenues for 2010 decreased by $6.1 million, or less than 1%, compared to 2009 as a result of the following (in millions):

	Increase
	(Decrease)

Lower average offshore day rates	$	(62.2	)
Lower offshore rig utilization		(49.2	)
Lower average land day rates		(23.3	)
Addition of two land rigs1		4.1
Reimbursables and other, net		5.0
Higher land rig utilization		37.0
Addition of the Ralph Coffman and EXL I2		82.5
Net decrease	$	(6.1	)

_______________________________

1In the first and second quarters of 2009, we added two land rigs to the fleet, which together contributed an additional 162 revenue-producing days in 2010 as compared to 2009.

2The Ralph Coffman and EXL I were added to the fleet in the first and second quarters of 2010 and together contributed 567 revenue-producing days in 2010.

The following table presents certain key performance measures by geographic area for our offshore fleet for 2010 and 2009. Revenues include those attributable to reimbursable costs. Average day rates are computed by dividing revenues recognized during the year, excluding reimbursables, by the number of revenue-producing days. Rig utilization is computed as the number of revenue-producing days divided by total available rig days.

	2010			2009

Gulf of Mexico:
Revenues	$	286,356,000		$	297,206,000
Average day rate	$	133,600		$	145,600
Utilization		68	%		64	%

Middle East:
Revenues	$	285,950,000		$	373,059,000
Average day rate	$	140,900		$	153,300
Utilization		61	%		74	%

North Sea:
Revenues	$	179,828,000		$	172,610,000
Average day rate	$	227,100		$	243,400
Utilization		94	%		97	%

Other international:
Revenues	$	264,348,000		$	199,449,000
Average day rate	$	205,000		$	257,600
Utilization		92	%		83	%

Drilling operating costs in 2010 increased by $28.8 million, or by 5% from 2009, primarily due to personnel and related costs attributable to the 2010 fleet additions of the Ralph Coffman and EXL I. An analysis of changes in drilling operating costs follows (in millions):

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	Increase
	(Decrease)			% Change

Personnel and related costs	$	23.0			8	%
Repairs and maintenance		7.9			8	%
Reimbursable expenses		4.4			23	%
Rig insurance costs		(4.7	)		-11	%
All other		(1.8	)		-2	%
Net increase	$	28.8			5	%

Our average operating margin (which we define as revenues in excess of drilling operating costs, other than depreciation and selling, general and administrative expenses), declined to 54% of revenues in 2010 from 57% in 2009, due to lower average day rates in 2010. Drilling depreciation expense increased by $14.3 million or 9% between periods due primarily to the addition of the Ralph Coffman and EXL I. Selling, general and administrative expenses increased by $17.0 million or 25% over 2009 due primarily to a $5.3 million provision for the cost of terminating the Company’s agency agreement in Mexico and higher personnel-related costs and professional fees.

2009 Compared to 2008

The following table highlights the performance of our Drilling Services segment during 2009 compared to 2008 (dollars in millions, except day rates):

	2009						2008
	Amount			% of Revenues			Amount			% of Revenues

Revenues	$	1,214.9			100	%	$	1,451.6			100	%
Operating costs		(525.2	)		-43	%		(629.8	)		-43	%
Depreciation expense		(155.9	)		-13	%		(125.9	)		-9	%
Selling, general and administrative expenses		(68.0	)		-6	%		(69.2	)		-5	%
Gains on property disposals		6.3			1	%		68.0			5	%
Material charges and other operating expenses		-			0	%		(24.6	)		-2	%
Operating income	$	472.1			39	%	$	670.1			46	%

Offshore fleet:
Average day rate	$	175,100					$	163,200
Revenue-producing days		5,876						7,313
Available rig days		8,030						7,663
Rig utilization		73	%					95	%

Land fleet:
Average day rate	$	23,200					$	22,600
Revenue-producing days		7,175						10,067
Available rig days		11,503						10,779
Rig utilization		62	%					93	%

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The following table summarizes average prices for oil and natural gas and our utilization and average day rates by quarter in 2009, and for the full years 2009 and 2008 for our offshore fleet:

	Oil (per bbl) *		Natural gas (per MCF) *		Average utilization			Average day rate
2009:
First quarter	$	43.14	$	4.47		93	%	$	173,600
Second quarter	$	59.61	$	3.81		78	%	$	177,200
Third quarter	$	68.14	$	3.44		59	%	$	182,500
Fourth quarter	$	76.00	$	4.93		63	%	$	167,700
Full year:
2009	$	61.95	$	4.16		73	%	$	175,100
2008	$	99.67	$	8.90		95	%	$	163,200

__________

*	Source: New York Mercantile Exchange (NYMEX)

The dramatic declines in oil and natural gas prices that began in mid 2008 coupled with the weakness in the global capital markets increased our customers’ efforts to preserve liquidity and adversely affected the economics of certain drilling projects. Most oil and gas producers significantly reduced their 2009 drilling expenditures, and that reduction was most prominent for shallow water and onshore projects. The reduction in demand reduced global jack-up and land rig utilization, increased competition among available rigs for fewer drilling assignments, and pressured day rates.

Drilling revenues for 2009 decreased by $236.7 million, or 16%, compared to 2008 as a result of the following (in millions):

	Increase
	(Decrease)

Lower offshore rig utilization	$	(274.7	)
Lower land rig utilization		(86.3	)
Loss of the Rowan-Anchorage1		(15.2	)
Reimbursables and other, net		(10.8	)
Higher average land day rates		1.9
Addition of four land rigs2		23.3
Higher average offshore day rates		45.6
Addition of the J.P. Bussell and Rowan-Mississippi3		79.5
Net decrease	$	(236.7	)

_______________________________

1The Rowan-Anchorage was lost in September 2008 during Hurricane Ike.

2The four land rigs added to the fleet over the period from May 2008 through June 2009 contributed an additional 939 revenue-producing days in 2009 as compared to 2008.

3The J.P. Bussell and Rowan-Mississippi commenced operations in November 2008 and contributed 548 revenue-producing days in 2009, as compared to 86 days in 2008.

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The following table presents certain key performance measures by geographic area for our offshore fleet for 2009 and 2008. Revenues include those attributable to reimbursable costs. Average day rates are computed by dividing revenues recognized during the year, excluding reimbursables, by the number of revenue-producing days. Rig utilization is computed as the number of revenue-producing days divided by total available rig-days.

	2009			2008

Gulf of Mexico:
Revenues	$	297,206,000		$	402,696,000
Average day rate	$	145,600		$	129,900
Utilization		64	%		97	%

Middle East:
Revenues	$	373,059,000		$	480,981,000
Average day rate	$	153,300		$	155,400
Utilization		74	%		94	%

North Sea:
Revenues	$	172,610,000		$	166,486,000
Average day rate	$	243,400		$	244,900
Utilization		97	%		91	%

Other international:
Revenues	$	199,449,000		$	158,988,000
Average day rate	$	257,600		$	301,200
Utilization		83	%		98	%

Drilling operating costs in 2009 decreased by $104.6 million, or 17% from 2008, as set forth in the table below (in millions):

	Increase
	(Decrease)			% Change

Personnel and related costs	$	(55.3	)		-16	%
Repairs and maintenance		(27.5	)		-21	%
Reimbursable expenses		(9.8	)		-34	%
Rig insurance costs		(3.1	)		-7	%
All other		(8.9	)		-11	%
Net decrease	$	(104.6	)		-17	%

The declines in personnel and related costs and repairs and maintenance expenses were primarily the result of reduced activity levels. Additionally, several shipyard upgrade projects on many of our idle rigs absorbed certain personnel-related costs and resulted in lower routine repair and maintenance expenses that we would have otherwise incurred. Our average operating margin (revenues in excess of operating costs, other than depreciation and selling, general and administrative expenses) was 57% of revenues in both 2009 and 2008. Drilling depreciation expense increased by $30.0 million or 24% between periods due primarily to the addition of the J.P. Bussell and Rowan-Mississippi in November 2008.

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Outlook

Our drilling backlog by geographic area as of February 25, 2011 (the date of our most recent “Rig Fleet and Contract Status” report), as compared to the prior-year amount, is set forth below (in millions):

	February 25, 2011		February 16, 2010

Middle East	$	621	$	275
North Sea		608		327
Gulf of Mexico		274		234
Other international		156		240
Subtotal - offshore		1,659		1,076
Land		143		234
Total drilling backlog	$	1,802	$	1,310

We estimate our drilling backlog will be realized as follows (in millions):

	Offshore		Land		Total

2011	$	718	$	75	$	793
2012		618		37		655
2013		243		14		257
2014		80		14		94
2015		-		3		3
Total drilling backlog	$	1,659	$	143	$	1,802

About 44% of our remaining available offshore rig days in 2011 and 26% of available days in 2012 were under contract or commitment as of February 25, 2011.

As of February 25, 2011, fifteen of our offshore rigs had drilling contracts estimated to complete in 2011, three had contracts or commitments estimated to complete in 2012, one had a contract estimated to complete in 2013, three had contracts estimated to complete in 2014, and six were available. Additionally, the Rowan Norway, which is currently under construction with an expected delivery date of June 2011, has a 240-day contract for work in the UK sector of the North Sea beginning in late 2011, plus a one-year priced option. One of the two remaining rigs under construction has a verbal commitment for up to about one year of work, and the other rig under construction was without a commitment.

In each of the past several years, the onset of hurricane season has coincided with declines in drilling activity in the US GOM. We expect this pattern to continue in future years.

In response to the Deepwater Horizon incident on April 20, 2010, and subsequent oil spill, the U.S. Secretary of the Interior on May 27, 2010, announced a moratorium on U.S. offshore deepwater drilling, which was subsequently lifted on October 12, 2010. In addition, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), which was formerly known as the Minerals Management Service, issued Notices to Lessees (NTLs) implementing new safety regulations applicable to drilling operations in the Gulf of Mexico. These NTLs have adversely impacted the ability of our customers to obtain necessary permits and approval on a timely basis and/or to continue operations uninterrupted under existing permits. On October 15, 2010, the BOEMRE issued new regulations which formalized many of the requirements set forth in the NTLs and issued additional environmental and safety requirements. We believe the impact of the NTLs and delayed permitting process on our US GOM operating results has not been significant to date; however, we can provide no assurance that will continue to be the case going forward.

In recent years, we have significantly expanded our operations internationally. Foreign operations are often subject to political, economic and other uncertainties not typically encountered in domestic operations. Recent political unrest in Egypt and other Middle East countries could spread to nearby areas where we have operations. Such unrest could potentially delay projects, either planned or currently in progress, or could impact the Company in other unforeseen ways. Any such unforeseen events could have a material adverse effect on our financial position, results of operations and cash flows. We

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currently have three rigs operating in Saudi Arabia, three rigs operating in Qatar, one rig in a shipyard in Bahrain undergoing modifications for a contract in Saudi Arabia, three idle rigs in Dubai, and one idle rig in Egypt.

We believe there are currently 67 jack-ups under construction for completion over the next three years, most of which do not have drilling contracts in place. Delivery of those rigs is expected to further increase competition among jack-up contractors. Thus, we can provide no assurance that we will be able to continue to replace our contract backlog as it is realized, that we can maintain current utilization levels, that spot day rates will remain above breakeven levels, or that our drilling operations will remain profitable.

Manufacturing Operations

Overview

Our manufacturing operations are conducted by LeTourneau Technologies, Inc, a wholly owned subsidiary of the Company, and consist of two business segments – Drilling Products and Systems and Mining, Forestry and Steel products.

The Drilling Products and Systems segment provides equipment, parts and services for the offshore and onshore oil and gas drilling industry. Featured products include complete jack-up rigs, rig kits and component packages, primary drilling equipment such as mud pumps, drawworks, top drives and rotary tables, and electrical components such as variable-speed motors and drives. Our Drilling Products and Systems segment is currently constructing our third 240C class rig, the Joe Douglas, for delivery later in 2011.

The Mining, Forestry and Steel Products segment produces large-wheeled mining and timber equipment and related parts and carbon and alloy steel and steel plate.

Demand for our manufactured products is significantly influenced by the level and direction of world commodities prices. Results for our Drilling Products and Systems segment are highly correlated to the condition of the oil and gas production industry and demand for drilling equipment, parts and services, which are in turn impacted by the level and direction of oil and natural gas prices. The prospects for our Mining, Forestry and Steel Products segment are strongly affected by prices for copper, iron ore, coal and timber.

Our manufacturing revenues in any period are impacted by the timing of product shipments, and our profitability is affected in part by the mix of product sales. Original equipment sales, for example, have traditionally yielded lower margins than the related after-market parts sales. Land rigs and component packages typically require more costs for commissioning than do individual pumps and other drilling equipment, and often carry a package discount. Thus, our gross margins are typically higher on equipment sales than on rigs and component packages.

2010 Compared to 2009

Drilling Products and Systems

The following table highlights the performance of our Drilling Products and Systems segment in 2010 and 2009 (dollars in millions):

	2010						2009
	Amount			% of Revenues			Amount			% of Revenues

Revenues	$	310.3			100	%	$	369.4			100	%
Operating costs		(305.8	)		-99	%		(341.0	)		-92	%
Depreciation expense		(8.6	)		-3	%		(9.0	)		-2	%
Selling, general and administrative expenses		(26.9	)		-9	%		(16.0	)		-4	%
Material charge - manufacturing inventories		(42.0	)		-14	%		-			0	%
Operating income (loss)	$	(73.0	)		-24	%	$	3.4			1	%

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Revenues from Drilling Products and Systems decreased by $59.1 million or 16% between periods due to the following (in millions):

	Increase
	(Decrease)

Higher revenues recognized on offshore rig kits in progress	$	70.7
Lower sales of land rigs and rig kits		(62.3	)
Lower sales of power system packages and motors		(33.4	)
Lower mud pump sales		(22.9	)
Lower parts sales		(8.1	)
Other, net		(3.1	)
Net decrease	$	(59.1	)

Our average operating margin (revenues in excess of operating costs, other than depreciation and selling, general and administrative expenses and material charges) declined to 1% of revenues in 2010 from 8% in 2009. The lower margin in 2010 was primarily attributable to much lower sales volumes and higher warranty costs. (Management believes that average operating margin, as defined, is a more meaningful measure of performance in a discussion of results of manufacturing operations, than absolute changes in operating costs.)

Selling, general and administrative costs increased by $10.9 million between periods due primarily to the addition of personnel in the fourth quarter of 2009 and first quarter of 2010, incremental costs in connection with a quality initiative at the Company’s manufacturing operations and due to higher bad debt expense.

In early 2010, the Drilling Products and Systems segment performed an assessment of its Houston-based raw materials and supplies inventory. As a result of the assessment, the Company increased its inventory valuation reserve by approximately $42.0 million and recorded a corresponding charge to expense in the first quarter of 2010. See “Inventories” in Note 2 of Notes to Consolidated Financial Statements for further information.

Our Drilling Products and Systems operating results for 2010 exclude $205.0 million of revenues and $148.3 million of expenses in connection with sales of products and services to our Drilling Services segment, most of which was attributable to construction of the newbuild jack-up, Joe Douglas. Drilling Products and Systems operating results for 2009 excludes $278.9 million of revenues and $182.3 million of expenses most of which was attributable to construction of the newbuild jack-up, Ralph Coffman, and kits and equipment provided for our EXL rigs.

Mining, Forestry and Steel Products

The following table highlights the performance of our Mining, Forestry and Steel Products segment for 2010 and 2009 (dollars in millions):

	2010						2009
	Amount			% of Revenues			Amount			% of Revenues

Revenues	$	300.1			100	%	$	185.9			100	%
Operating costs		(206.5	)		-69	%		(134.6	)		-72	%
Depreciation expense		(7.8	)		-3	%		(6.5	)		-3	%
Selling, general and administrative expenses		(20.6	)		-7	%		(18.8	)		-10	%
Net loss on property disposals		(0.2	)		0	%		(0.5	)		0	%
Operating income	$	65.0			22	%	$	25.5			14	%

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Revenues from Mining, Forestry and Steel Products increased by $114.2 million or 61% between periods due to the following (in millions):

	Increase
	(Decrease)

Higher sales of mining loaders (25 loaders in 2010 compared to 14 in 2009)	$	63.0
Higher sales of parts		35.2
Higher sales of steel plate		7.7
Other, net		8.3
Net increase	$	114.2

Our average operating margin (revenues in excess of operating costs, other than depreciation and selling, general and administrative expenses) increased to 31% of revenues in 2010 from 28% in 2009. The higher margin was attributable to increased sales volumes as well as product sales mix, particularly a greater proportion of higher-margin mining loaders and parts sales in 2010. Selling, general and administrative expenses increased by $1.8 million or 10% between periods primarily due to the settlement of a 2001 Chilean arbitration in connection with the loss of a loader sustained by a customer.

2009 Compared to 2008

Drilling Products and Systems

The following table highlights the performance of our Drilling Products and Systems segment for 2009 and 2008 (dollars in millions):

	2009						2008
	Amount			% of Revenues			Amount			% of Revenues

Revenues	$	369.4			100	%	$	493.5			100	%
Operating costs		(341.0	)		-92	%		(421.5	)		-85	%
Depreciation expense		(9.0	)		-2	%		(9.5	)		-2	%
Selling, general and administrative expenses		(16.0	)		-4	%		(25.1	)		-5	%
Material charges and other operating expenses		-			0	%		(81.9	)		-17	%
Net gain (loss) on property disposals		-			0	%		(0.1	)		0	%
Operating income (loss)	$	3.4			1	%	$	(44.6	)		-9	%

Revenues from Drilling Products and Systems decreased by $124.1 million, or 25%, between periods due primarily to the following:

·	A decrease of $78.0 million attributable to $111.6 million of revenues recognized on five offshore rig kit projects in 2009, as compared to $189.6 million recognized on eight projects in 2008;

·	A decrease of $36.3 million attributable to $103.0 million recognized on shipments of land rigs and component packages in 2009, down from $139.3 million in 2008;

·	A decrease of $23.8 million attributable to $1.9 million of revenues recognized on shipments of top drives in 2009, down from $25.7 million in 2008;

·	An increase of $8.6 million attributable to $50.1 million recognized on 57 mud pumps shipped in 2009, up from $41.5 million on 63 pumps in 2008.

Our average operating margin (revenues in excess of operating costs, other than depreciation, selling, general and administrative expenses and material charges) decreased to 8% of revenues in 2009 from 15% in 2008. Margins in 2009 were negatively affected by sales mix, with a greater share of revenues from some of our lower-margin products as compared to the prior year and poor results on several land rig projects.

Selling, general and administrative costs declined by $9.1 million or 36% between periods due primarily to lower compensation and related fringe benefit costs associated with reduced employment levels.

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Our Drilling Products and Systems operating results for 2009 exclude $278.9 million of revenues and $182.3 million of expenses in connection with sales of products and services to our Drilling Services segment, much of which was attributable to construction of the newbuild jack-up, Ralph Coffman, and kits and equipment provided for our EXL rigs. Drilling Products and Systems operating results for 2008 excludes $382.9 million of revenues and $307.7 million of expenses, primarily for construction of the J.P. Bussell, Rowan-Mississippi and Ralph Coffman.

Mining, Forestry and Steel Products

The following table highlights the performance of our Mining, Forestry and Steel Products segment for 2009 and 2008 (dollars in millions):

	2009						2008
	Amount			% of Revenues			Amount			% of Revenues

Revenues	$	185.9			100	%	$	267.6			100	%
Operating costs		(134.6	)		-72	%		(203.3	)		-76	%
Depreciation expense		(6.5	)		-3	%		(6.1	)		-2	%
Selling, general and administrative expenses		(18.8	)		-10	%		(20.8	)		-8	%
Material charges and other operating expenses		-			0	%		(4.7	)		-2	%
Net loss on property disposals		(0.5	)		0	%		(0.1	)		0	%
Operating income	$	25.5			14	%	$	32.6			12	%

Revenues from Mining, Forestry and Steel Products decreased by $81.7 million or 31% between periods due primarily to the following:

·	Lower sales of new mining loaders and forestry stackers, which declined by $38.9 million or 38%, from $102.6 million in 2008 to $63.7 million in 2009. We shipped 14 new mining loaders and forestry stackers in 2009, as compared to 29 units in 2008;

·	Lower sales of steel plate, which declined by $35.0 million or 52%, from $66.9 million in 2008 to $31.9 million in 2009;

·	A two-percent increase in part sales, to $73.3 million in 2009 from $71.9 million in 2008.

Our average operating margin (revenues in excess of operating costs, other than depreciation, selling, general and administrative expenses and material charges) increased to 28% of revenues in 2009 from 24% in 2008. The higher margins were attributable to primarily product sales mix, particularly a greater proportion of higher-margin after-market parts and service revenues in 2009. (Management believes that average operating margin, as defined, is a more meaningful measure of performance in a discussion of results of manufacturing operations, than absolute changes in operating costs.)

Outlook

Our external manufacturing backlog includes executed contracts and customer commitments and comprised the following (in millions):

	December 31,
	2010		2009

Mining, Forestry, and Steel Products - Mining loaders	$	132	$	67
Drilling Products and Systems - Offshore rig projects		70		217
Drilling Products and Systems - Land rig projects		38		71
Drilling Products and Systems - Drilling equipment		22		29
Drilling Products and Systems - Parts, power systems and other components		20		14
Mining, Forestry, and Steel products - Other parts and steel products		17		15
Total manufacturing backlog	$	299	$	413

We expect a substantial majority of our external manufacturing backlog at December 31, 2010, will be realized as revenue in 2011. The changes reflected in the table above were indicative of the trends for most of 2010 in each of our significant product lines. Beginning in late 2010 and more recently, however, requests for quotations have increased at Drilling

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Products and Systems, especially for offshore rig kits and related drilling equipment packages. We believe we will be successful at obtaining new business in these areas.

As reflected in the preceding table, our backlog of mining and forestry equipment improved significantly during 2010. In December 2010, we received an order to manufacture and deliver 15 front-end wheel loaders, valued at approximately $85 million, which is included in our backlog at December 31. The loaders, purchased by a single customer for iron ore mining operations in Brazil, are scheduled for delivery throughout 2011. The global mining equipment market has been increasingly active throughout 2010 and into 2011, and we believe 2011 will be a strong year for our Mining Products business.

We can provide no assurance we will be able to maintain or significantly increase our backlog going forward.

We currently have no further plans for rig construction at our Vicksburg shipyard following the delivery of our third 240C-class rig, the Joe Douglas, in 2011, but may continue to use the facility for other operations. Absent additional orders or sufficient prospects for future work, the activities at the facility would be significantly reduced at that time, in which case we would incur additional costs such as employee severance, among other charges. Closing or significantly reducing activity levels at the facility could result in the incurrence of cash charges ranging from $8 million to $10 million.

LIQUIDITY AND CAPITAL RESOURCES

Key balance sheet amounts and ratios for 2010 and 2009 were as follows (dollars in millions):

	December 31,
	2010		2009

Cash and cash equivalents	$	437.5	$	639.7
Current assets	$	1,324.8	$	1,549.8
Current liabilities	$	529.2	$	568.3
Current ratio		2.50		2.73
Current maturities of long-term debt	$	52.2	$	64.9
Long-term debt, less current maturities	$	1,133.7	$	787.5
Stockholders' equity	$	3,752.3	$	3,110.4
Long-term debt/total capitalization		0.23		0.20

Reflected in the comparison above are the effects of the following sources and uses of cash and cash equivalents in 2010, with comparable amounts for 2009:

	2010			2009

Net operating cash flows	$	508.2		$	544.1
Borrowings, net of issue costs		395.5			491.7
Proceeds from equity compensation and debenture plans and other		8.0			1.5
Proceeds from asset disposals		3.3			8.6
Net change in restricted cash balance		(15.3	)		-
Net cash used in acquisition of SKDP		(17.7	)		-
Capital expenditures		(490.6	)		(566.4	)
Debt repayments		(594.0	)		(64.9	)
All other, net		0.4			2.7
Total sources (uses)	$	(202.2	)	$	417.3

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Operating Cash Flows

Our cash flows from operations in 2010 and 2009 have benefited from long-term drilling contracts entered into when rates were significantly higher than current market rates. As a result, operating cash flows have been and may continue to be negatively affected as these higher day-rate contracts are completed. This impact, however, has been and should continue to be at least partially offset as a result of our newbuild offshore rig additions, particularly in 2010 and planned for 2011. Management believes that 2011 cash flow from operating activities will not be sufficient to fund its current rig construction program, which should be completed in 2011, and its 2011 debt service requirements, and as a result, anticipates drawing down on the Company’s $350 million term loan facility in the first half of the year. (See further discussion under “Financing Activities.”)

Investing Activities

In September 2010, we completed our acquisition of Skeie Drilling & Production ASA, a Norwegian entity that owned and managed the construction of three high-spec jack-up rigs, designated “N-Class,” designed and being built by Keppel FELS Ltd. in Singapore. In connection with the transaction, the Company issued 11.7 million shares of Rowan common stock valued at $338 million, assumed first and second lien debt with a par value of $492 million as of the September 10, 2010 acquisition date (the “Acquisition Date”) and acquired net cash of $201 million, including restricted cash of $219 million. We used the $219 million of restricted cash in the fourth quarter of 2010 to make the final shipyard payment for the Rowan Viking. Capital expenditures for 2010 are reported net of this final payment.

Refer to Note 7 of Notes to Consolidated Financial Statements in this Form 10-K regarding the status of our newbuild rig projects.

Significant capital expenditures in 2010 included the following:

·	$235 million towards construction of the four EXL-class rigs;

·	$102 million towards construction of our third 240C-class rig, the Joe Douglas;

·	$89 million for improvements to the existing offshore fleet;

·	$8 million towards construction of the Rowan Viking, Rowan Stavanger and Rowan Norway (net of $219 million of restricted cash acquired from SKDP); and

·	$57 million for equipment spares, drill pipe and other.

Our 2011 capital budget, as approved by our Board of Directors, is approximately $1.06 billion, and includes $500 million for the completion of the Rowan Stavanger and Rowan Norway, $154 million for completion of the Joe Douglas and the EXL IV, $213 million for upgrades to existing rigs and spare drilling equipment, $159 million pursuant to contractual requirements that will be substantially reimbursed by customers, and $38 million for manufacturing facilities and other.

The capital budget reflects an appropriation of money that we may or may not spend, and the timing of such expenditures may change. We will periodically review and adjust the capital budget as necessary based upon current and forecasted cash flows and liquidity, anticipated market conditions in our drilling and manufacturing businesses, the availability of financing sources, and alternative uses of capital to enhance shareholder value. Certain such adjustments would require Board approval.

Financing Activities

On August 30, 2010, we completed the issuance and sale of $400 million aggregate principal amount of 5.0% Senior Notes due September 1, 2017 (the “5% Senior Notes”). Net proceeds to the Company, after underwriting discount and offering expenses, were $395.5 million, which we used in 2010 to retire higher-coupon SKDP debt. Interest on the Senior Notes is payable semi-annually on March 1 and September 1 of each year, commencing March 1, 2011.

The Company may, at its option, redeem all or part of the 5% Senior Notes at any time at a make-whole price. The 5% Senior Notes are general unsecured, senior obligations. Accordingly, the 5% Senior Notes rank (i) pari passu in right of payment with any of the Company’s existing and future unsecured indebtedness that is not by its terms subordinated to the 5% Senior Notes, including any indebtedness under the Company’s senior revolving credit facility (other than letter of credit reimbursement obligations that are secured by cash deposits), (ii) effectively junior to the Company’s existing and future secured indebtedness (including indebtedness under its secured notes issued pursuant to the MARAD Title XI program to finance several offshore drilling rigs), in each case, to the extent of the value of the Company’s assets constituting collateral

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securing that indebtedness and (iii) effectively junior to all existing and future indebtedness and other liabilities of the Company’s subsidiaries (other than indebtedness and liabilities owed to the Company).

In connection with the acquisition of SKDP, we assumed first and second lien SKDP bonds with a par value of approximately $225 million and $267 million, respectively, as of the Acquisition Date. The first and second lien bonds were revalued and recognized at fair value aggregating $250 million and $279 million, respectively. In the third and fourth quarters of 2010, we retired all of the SKDP debt through a combination of open market purchases and redemption, and recognized a net gain on extinguishment of $5.3 million in 2010. Such amount is included in other income and expense on the Consolidated Statement of Income.

Certain of the SKDP bondholders disputed our ability to call the debt in 2010; consequently, we deposited in escrow with the bond trustee $15.3 million, which is classified as restricted cash on our Consolidated Balance Sheet at December 31, 2010, to cover interest that would accrue on the first lien bonds until their May 2011 call date, and on the second lien bonds until their respective call dates in February, March and July 2011. We expect to prevail in this matter and fully recoup the escrowed amount.

On September 16, 2010, we terminated our $155 million revolving credit facility agreement dated June 23, 2008, and entered into a new credit agreement with a group of banks (the “2010 Credit Agreement”) under which we may borrow up to $250 million on a revolving basis through September 16, 2014, and up to $350 million on a term basis. The term loan has a final maturity date of September 16, 2015. Term advances are limited to reimbursements for repayments of debt assumed in the SKDP acquisition and must be drawn by July 31, 2011. Interest and commitment fees payable under the 2010 Credit Agreement are based in part on the Company’s then current credit ratings. The annual commitment fee is currently .45% of the unused commitment. Advances would currently bear interest at Libor plus 2.375% per annum. There were no amounts drawn under the 2010 Credit Agreement at December 31, 2010. The 2010 Credit Agreement limits total consolidated indebtedness and contains events of default, the occurrence of which may trigger an acceleration of amounts outstanding under the agreement.

We currently expect to fully draw down our $350 million term loan facility over the first half of 2011. Our $250 million revolving credit facility should remain undrawn in 2011. We currently estimate our interest cost for 2011 to be in the $80 million range, of which approximately 40% would be capitalized as part of our rig construction costs.

We were in compliance with each of our debt covenants at December 31, 2010, and we expect to remain in compliance in 2011.

Pension Obligations

Minimum pension contributions are determined based upon actuarial calculations of pension assets and liabilities that involve, among other things, assumptions about long-term asset returns and interest rates. Similar calculations were used to estimate pension costs and obligations as reflected in our consolidated financial statements. As of December 31, 2010, our financial statements reflected an aggregate unfunded pension liability of $159 million, most of which relates to our drilling employees’ plan. In order to slow the rate at which plan benefits were growing, we amended the benefit formula for new drilling plan entrants effective January 1, 2008, and further amended the plan for remaining active participants effective July 1, 2009. The plan changes that became effective in 2009 resulted in an approximately $15 million annualized reduction in pension expense. Despite the changes to the plan, we will continue to make significant pension contributions over the next several years, and additional funding would be required if asset values decline. We currently expect to make minimum contributions to our defined benefit pension plans of approximately $53 million in 2011.

Cash Dividends

The Company last paid a regular quarterly cash dividend in November 2008 and there are no current plans for dividend payments. Future dividends, if any, will only be paid at the discretion of the Board of Directors. At December 31, 2010, we had approximately $427 million available for distribution to stockholders under provisions of our debt agreements.

Off-balance Sheet Arrangements

The Company had no off-balance sheet arrangements as of December 31, 2010 or 2009, other than operating lease obligations and other commitments in the ordinary course of business (see “Contractual Obligations and Commercial Commitments” below).

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Contractual Obligations and Commercial Commitments

The following is a summary of our contractual obligations at December 31, 2010 (dollars in millions):

	Payments due by period
	Total		Within 1 year		2 to 3 years		4 to 5 years		After 5 years

Long-term debt, including interest	$	1,737	$	122	$	218	$	175	$	1,222
Newbuild construction contracts		654		654		-		-		-
Purchase obligations, excluding newbuilds		60		60		-		-		-
Operating leases		27		6		7		5		9
Total	$	2,478	$	842	$	225	$	180	$	1,231

We periodically employ letters of credit or other bank-issued guarantees in the normal course of our businesses, and had outstanding letters of credit of approximately $70.3 million at December 31, 2010.

Based on current and anticipated near-term operating levels, we believe that operating cash flows together with existing working capital and the anticipated drawdown of our $350 million term loan facility in 2011 will be adequate to sustain planned capital expenditures and debt service and other requirements in 2011.

Contingent Liabilities

Reference should be made to Note 7 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K for a discussion of the status of significant legal proceedings.

Critical Accounting Policies and Management Estimates

Rowan’s significant accounting policies are presented in Note 2 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K. These policies, and management judgments, assumptions and estimates made in their application underlie reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. We believe that our most critical accounting policies and management estimates involve revenue recognition for longer-term manufacturing contracts accounted for under the percentage-of-completion method of accounting, inventories (primarily valuation allowances for excess and obsolete inventories), carrying values of long-lived assets, pension and other postretirement benefit liabilities and costs (specifically assumptions used in actuarial calculations), and income taxes (particularly our estimated reserves for uncertain tax positions), as changes in such policies and/or estimates would produce significantly different amounts from those reported herein.

Revenue recognition under the percentage of completion method

We generally recognize manufacturing sales and related costs when title passes as products are shipped. Revenues from longer-term contracts such as for the construction of offshore rigs and rig kits are recognized on the percentage-of-completion basis using contract costs incurred relative to total estimated project costs. An offshore rig construction project typically occurs over a two-year period at our Vicksburg, Mississippi, shipyard and includes a significant labor cost component for fabrication and assembly. A rig kit includes selected rig components and parts manufactured over a six- to nine-month period in our Longview, Texas, facility. Costs are recorded separately for each offshore rig or rig kit project, and by significant activity or component within each project, and include materials issued to the project, labor expenses that are incurred directly for the project and overhead expenses that are allocated across all projects at consistent rates per labor hour. Incurred costs include only those that measure project work performed. Material costs incurred, for example, do not include materials purchased but remaining in inventory; only when such materials have been used in production on the project are they included in incurred project costs. The determination of total estimated project costs is performed monthly based upon then-current information. This process involves an evaluation of progress towards project milestones and an assessment of work left to complete each project activity or component, and is based on physical observations by project managers and engineers. An estimate of project costs is then developed for each significant activity or component based upon the assessment of project status, actual costs incurred to date and outstanding commitments for project materials and services. We do not recognize any estimated profit until such projects are at least 10% complete, though a full provision is made immediately for any anticipated losses.

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We have not experienced any significant fluctuations in the percentage-of-completion measurements in recent periods, nor have we incurred any losses on such projects. In 2010 we recognized $100.1 million of manufacturing revenues and $64.3 million of costs related to rig kit projects on the percentage-of-completion basis.

Inventories

Inventories are carried at the lower of average cost or estimated net realizable value. Costs include labor, material and an allocation of production overhead. We determine valuation allowances or reserves for inventories based on historical usage of inventories on hand, assumptions about future demand based on market conditions, and estimates about potential alternative uses, which are usually limited. Our inventories generally consist of spare parts, work in process, and raw materials to support ongoing manufacturing operations and the Company’s installed base of drilling, mining and timber equipment. Customers rely on us to stock these specialized items to ensure that their equipment can be repaired and serviced in a timely manner. The estimated carrying values of our inventories therefore ultimately depend upon demand driven by oil, natural gas and other commodity prices, general economic conditions worldwide and the potential obsolescence of various types of equipment we sell, among other factors. At December 31, 2010 and 2009, our inventory reserves totaled 16% and 8% of gross inventories, respectively. As a result of declines in oil and natural gas prices, the onset of global recession and weakness in capital markets in 2008, we reduced our estimates of the future usage of our drilling equipment inventories and significantly increased our inventory valuation reserves at December 31, 2008. In early 2010, we made a similar adjustment to the inventory valuation reserve in the amount of $42.0 million. See “Inventories” in Note 2 for further information.

Deterioration in worldwide demand for oil, natural gas and certain other commodities, or the development of new technologies which make older drilling, mining and timber equipment technologies obsolete, could require us to record additional reserves to reduce the value of our inventory.

Impairment of long-lived assets

We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. Generally, extended periods of idle time and/or our inability to contract rigs at economical rates are an indication that a rig may be impaired. However, the offshore drilling industry has historically been highly cyclical and it is not unusual for rigs to be unutilized or underutilized for extended periods of time and subsequently resume full or near full utilization when business cycles improve. Likewise, during periods of excess supply, rigs are frequently contracted at or near cash break-even rates for extended periods. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic region. Our rigs are mobile and may generally be moved from regions with excess supply, if economically feasible.

Asset impairment evaluations are, by nature, highly subjective. In most instances, they involve expectations of future cash flows to be generated by our drilling rigs and are based on management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of future expected utilization, contract rates, expense levels and capital requirements of our drilling rigs. The estimates, judgments and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.

Pension and other postretirement benefit liabilities and costs

Our pension and other postretirement benefit liabilities and costs are based upon actuarial computations that reflect our assumptions about future events, including long-term asset returns, interest rates, annual compensation increases, mortality rates and other factors. Key assumptions at December 31, 2010, included discount rates ranging from 5.26% to 5.46%, an expected long-term rate of return on pension plan assets of 8% and annual healthcare cost increases ranging from 8.4% in 2011 to 4.5% in 2029 and beyond. The assumed discount rate is based upon the average yield for Moody’s Aa-rated corporate bonds and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations. A one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $97 million, while a one-percentage-point change in the expected long-term rate of return on plan assets would change annual net benefits cost by approximately $3.8 million. A one-percentage-point increase in the assumed healthcare cost trend rate would increase 2011 other postretirement benefit cost by $0.5 million. To develop the expected long-term rate of return on assets assumption, Rowan considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes and the expectations for future returns of each asset class. The

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expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plan, which was maintained at 8% at December 31, 2010, unchanged from December 31, 2009.

Income taxes

In accordance with accounting guidelines for income tax uncertainties, we evaluate each tax position to determine if it is more likely than not that the tax position will be sustained upon examination, based on its merits. A tax position that meets the more-likely-than-not recognition threshold is subject to a measurement assessment to determine the amount of benefit to recognize in income for the period, and a reserve, if any. Our income tax returns are subject to audit by U.S. federal, state, and foreign tax authorities. Determinations by such taxing authorities that differ materially from our recorded estimates, either favorably or unfavorably, may have a material impact on our results of operations, financial position and cash flows. We believe our reserve for uncertain tax positions totaling $51.8 million at December 31, 2010, is properly recorded in accordance with the accounting guidelines.

New Accounting Standards

There have been no new accounting standards issued that are expected to have a material effect on the Company’s financial statements upon adoption.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Rowan’s outstanding debt at December 31, 2010, consisted entirely of fixed-rate debt with a carrying value of $1,186 million, bearing a weighted-average annual interest rate of 5.9%. Due to the fixed-rate nature of the Company’s debt, management believes the risk of loss due to changes in market interest rates is not material.

The majority of Rowan’s transactions are denominated in United States dollars. The Company has some exposure to currency exchange fluctuations primarily in Brazil and Australia as a result of its manufacturing presence in those countries. In order to reduce the impact of exchange rate fluctuations, Rowan generally requires customer payments to be in U.S. dollars and limits foreign currency holdings to the extent they are needed to pay liabilities denominated in such currencies. The Company recognized net foreign currency gains of $4.5 million and $5.4 million in 2010 and 2009 and a loss of $10.8 million in 2008, primarily attributable to operations in Australia and Brazil.

Fluctuating commodity prices affect Rowan’s future earnings materially to the extent that they influence demand for the Company’s products and services. As a general practice, Rowan does not hold or issue derivative financial instruments.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX	Page

Consolidated Balance Sheets, December 31, 2010 and 2009	43
Consolidated Statements of Income for the Years Ended December 31, 2010, 2009 and 2008	44
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008	45
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008	46
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008	47
Notes to Consolidated Financial Statements	48
Report of Independent Registered Public Accounting Firm	70
Management’s Report On Internal Control Over Financial Reporting	71
Report of Independent Registered Public Accounting Firm	72
Selected Quarterly Financial Data (Unaudited)	73

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Rowan Companies, Inc.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009
	(In thousands, except share amounts)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	437,479		$	639,681
Restricted cash		15,265			-
Receivables - trade and other		417,881			343,642
Inventories:
Raw materials and supplies		277,527			309,682
Work-in-progress		70,114			141,036
Finished goods		212			941
Prepaid expenses and other current assets		69,346			76,744
Deferred income taxes - net		36,945			38,071
Total current assets		1,324,769			1,549,797

PROPERTY, PLANT AND EQUIPMENT - at cost:
Drilling equipment		4,300,831			3,975,006
Manufacturing plant and equipment		248,326			251,882
Construction in progress		1,584,802			528,669
Other property and equipment		149,280			144,337
Property, plant and equipment - gross		6,283,239			4,899,894
Less accumulated depreciation and amortization		1,489,802			1,320,409
Property, plant and equipment - net		4,793,437			3,579,485

Other assets		99,251			81,412

TOTAL ASSETS	$	6,217,457		$	5,210,694

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	52,166		$	64,922
Accounts payable - trade		116,865			124,562
Deferred revenues		153,446			139,398
Billings in excess of costs and estimated profits on uncompleted contracts		7,915			25,226
Accrued liabilities		198,838			214,164
Total current liabilities		529,230			568,272

Long-term debt - less current maturities		1,133,745			787,490
Other liabilities		251,145			278,862
Deferred income taxes - net		551,027			465,700
Commitments and contingent liabilities (Note 7)		-			-

STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value, 5,000,000 shares authorized, issuable in series:
Series A Junior Preferred Stock, 1,500,000 shares authorized, none issued		-			-
Common stock, $0.125 par value, 150,000,000 shares authorized, 126,346,627 shares and 113,885,661 shares issued at December 31, 2010 and 2009, respectively		15,794			14,237
Additional paid-in capital		1,433,999			1,078,337
Retained earnings		2,449,521			2,169,526
Cost of 52,408 and 52,342 treasury shares at December 31, 2010 and 2009, respectively		(1,509	)		(1,409	)
Accumulated other comprehensive loss		(145,495	)		(150,321	)
Total stockholders' equity		3,752,310			3,110,370

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	6,217,457		$	5,210,694

See Notes to Consolidated Financial Statements.

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Rowan Companies, Inc.

CONSOLIDATED STATEMENTS OF INCOME

	For the years ended December 31,
	2010			2009			2008
	(In thousands, except per share amounts)
REVENUES:
Drilling services	$	1,208,766		$	1,214,896		$	1,451,623
Manufacturing sales and services		610,441			555,284			761,113
Total revenues		1,819,207			1,770,180			2,212,736

COSTS AND EXPENSES:
Drilling services (excluding items below)		553,906			525,157			629,795
Manufacturing sales and services (excluding items below)		512,384			475,553			624,815
Depreciation and amortization		186,563			171,445			141,395
Selling, general and administrative		132,586			102,760			115,226
Loss (gain) on disposals of property and equipment		788			(5,748	)		(30,701	)
Material charges and other operating expenses		42,024			-			111,171
Gain on hurricane-related event		-			-			(37,088	)
Total costs and expenses		1,428,251			1,269,167			1,554,613

INCOME FROM OPERATIONS		390,956			501,013			658,123

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(24,879	)		(8,028	)		(1,198	)
Interest income		1,508			1,240			6,295
Gain on debt extinguishment		5,324			-			-
Other - net		6,108			6,866			(9,129	)
Total other income (expense) - net		(11,939	)		78			(4,032	)

INCOME BEFORE INCOME TAXES		379,017			501,091			654,091
Provision for income taxes		99,022			133,587			226,463

NET INCOME	$	279,995		$	367,504		$	427,628

PER SHARE AMOUNTS:
Net income - basic	$	2.39		$	3.24		$	3.80
Net income - diluted	$	2.36		$	3.24		$	3.77

See Notes to Consolidated Financial Statements.

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Rowan Companies, Inc.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	For the years ended December 31,
	2010		2009		2008
	(In thousands)

NET INCOME	$	279,995	$	367,504	$	427,628
Other comprehensive income (loss):
Pension and other postretirement benefit adjustments, net of income tax expense (benefit) of $2,599, $35,912, and ($65,095), respectively		4,826		66,695		(120,891	)

COMPREHENSIVE INCOME	$	284,821	$	434,199	$	306,737

See Notes to Consolidated Financial Statements.

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Rowan Companies, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

	Shares of common stock outstanding			Common stock		Additional paid-in capital		Retained earnings			Treasury stock			Accumulated other comprehensive income (loss)			Total stockholders' equity
								(In thousands)

Balance, January 1, 2008		111,263		$	13,911	$	1,012,214	$	1,419,417		$	(979	)	$	(96,125	)	$	2,348,438
Stock issued under share-based compensation plans		1,828			230		33,551		-			-			-			33,781
Cash dividends ($0.40 per common share)		-			-		-		(45,023	)		-			-			(45,023	)
Stock-based compensation		-			-		14,754		-			-			-			14,754
Excess tax benefit from stock-based compensation plans		-			-		2,683		-			-			-			2,683
Treasury stock acquired		(55	)		-		-		-			(1,554	)		-			(1,554	)
Retirement benefit adjustments, net of taxes of ($65,095)		-			-		-		-			-			(120,891	)		(120,891	)
Net income		-			-		-		427,628			-			-			427,628
Balance, December 31, 2008		113,036			14,141		1,063,202		1,802,022			(2,533	)		(217,016	)		2,659,816
Stock issued under share-based compensation plans		797			96		336		-			1,124			-			1,556
Stock-based compensation		-			-		12,127		-			-			-			12,127
Excess tax benefit from stock-based compensation plans		-			-		2,672		-			-			-			2,672
Retirement benefit adjustments, net of taxes of $35,912		-			-		-		-			-			66,695			66,695
Net income		-			-		-		367,504			-			-			367,504
Balance, December 31, 2009		113,833			14,237		1,078,337		2,169,526			(1,409	)		(150,321	)		3,110,370
Stock issued to acquire SKDP		11,725			1,466		336,441		-			-			-			337,907
Stock issued under share-based compensation plans		736			91		4,343		-			(100	)		-			4,334
Stock-based compensation		-			-		14,466		-			-			-			14,466
Excess tax benefit from stock-based compensation plans		-			-		412		-			-			-			412
Retirement benefit adjustments, net of taxes of $2,599		-			-		-		-			-			4,826			4,826
Net income		-			-		-		279,995			-			-			279,995
Balance, December 31, 2010		126,294		$	15,794	$	1,433,999	$	2,449,521		$	(1,509	)	$	(145,495	)	$	3,752,310

See Notes to Consolidated Financial Statements.

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Rowan Companies, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the years ended December 31,
	2010			2009			2008
	(In thousands)
CASH PROVIDED BY OPERATIONS:
Net income	$	279,995		$	367,504		$	427,628
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization		186,563			171,445			141,395
Deferred income taxes		45,164			15,771			51,070
Material charge - manufacturing inventories		42,024			-			62,392
Provision for pension and postretirement benefits		33,960			39,664			32,479
Stock-based compensation expense		15,578			13,034			15,834
Contributions to pension plans		(57,266	)		(36,248	)		(31,749	)
Postretirement benefit claims paid		(3,588	)		(3,495	)		(3,017	)
Loss (gain) on disposals of property, plant and equipment		788			(5,748	)		(30,701	)
Estimated net benefits from income tax claims		-			(25,392	)		-
Goodwill impairment		-			-			13,606
Gain on hurricane-related event		-			-			(37,088	)
Changes in current assets and liabilities:
Receivables - trade and other		(34,268	)		147,340			(6,777	)
Inventories		65,177			92,357			(155,164	)
Prepaid expenses and other current assets		9,208			(17,278	)		1,703
Accounts payable		(34,799	)		(134,648	)		128,897
Accrued income taxes		(30,555	)		(17,327	)		32,062
Deferred revenues		14,048			(34,688	)		63,490
Billings in excess of costs and estimated profits on uncompleted contracts		(17,311	)		(31,893	)		(12,748	)
Other current liabilities		6,381			3,209			18,105
Net changes in other noncurrent assets and liabilities		(12,937	)		487			(16,948	)
Net cash provided by operations		508,162			544,094			694,469

CASH USED IN INVESTING ACTIVITIES:
Capital expenditures		(490,560	)		(566,383	)		(829,156	)
Proceeds from disposals of property, plant and equipment		3,267			8,592			56,108
Net cash used in acquisition of SKDP		(17,681	)		-			-
(Increase) decrease in restricted cash		(15,265	)		-			50,000
Proceeds from hurricane-related event		-			-			41,550
Net cash used in investing activities		(520,239	)		(557,791	)		(681,498	)

CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES:
Repayments of borrowings		(594,013	)		(64,922	)		(144,922	)
Proceeds from borrowings, net of issue costs		395,517			491,729			80,000
Proceeds from stock option and convertible debenture plans		7,959			1,471			33,781
Excess tax benefits from stock-based compensation		412			2,672			2,683
Payment of cash dividends		-			-			(44,989	)
Payments to acquire treasury stock		-			-			(1,554	)
Net cash provided by (used in) financing activities		(190,125	)		430,950			(75,001	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(202,202	)		417,253			(62,030	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		639,681			222,428			284,458
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	437,479		$	639,681		$	222,428

See Notes to Consolidated Financial Statements.

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Rowan Companies, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Rowan Companies, Inc., operating through its drilling subsidiaries, is a major provider of international and domestic oil and gas contract drilling services. Rowan’s wholly owned manufacturing subsidiary, LeTourneau Technologies, Inc. (“LeTourneau”), produces equipment for the international and domestic oil and gas drilling, mining and timber industries.

The consolidated financial statements are presented in U.S. dollars in accordance with accounting principles generally accepted in the United States of America and include the accounts of Rowan Companies, Inc. and its subsidiaries (hereafter referred to as “Rowan” or the “Company”), all of which are wholly owned. Intercompany balances and transactions are eliminated in consolidation.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue and Expense Recognition

Drilling Services. Rowan’s drilling contracts generally provide for payment on a daily rate basis, and revenues are recognized as the work progresses with the passage of time. Rowan frequently receives lump-sum payments at the outset of a drilling assignment for equipment moves or modifications. Lump-sum fees received for equipment moves (and related costs) and fees received for equipment modifications or upgrades are initially deferred and amortized on a straight-line basis over the primary term of the drilling contract. The costs of contractual equipment modifications or upgrades, as well as the costs associated with the initial move of newly delivered rigs, are capitalized and depreciated in accordance with the Company’s fixed asset capitalization policy. The costs of moving equipment while not under contract are expensed as incurred. Drilling revenues received but unearned are included in current and long-term liabilities and totaled $9.5 million and $38.4 million at December 31, 2010 and 2009, respectively. Deferred drilling costs are included in prepaid expenses and other assets and totaled $22.3 million and $27.5 million at December 31, 2010 and 2009, respectively.

Rowan also recognizes revenue for certain reimbursable costs. Each reimbursable item and amount is stipulated in the Company’s contract with the customer, and such items and amounts frequently vary between contracts. The Company recognizes reimbursable costs on the gross basis, as both revenues and expenses, because Rowan is the primary obligor in the arrangement, has discretion in supplier selection, is involved in determining product or service specifications and assumes full credit risk related to the reimbursable costs.

Manufacturing Sales and Services. Rowan generally recognizes revenues and costs from sales of manufactured products when title passes as products are shipped. Revenues from longer-term contracts such as for the construction of offshore rigs and rig kits are recognized on the percentage-of-completion basis using contract costs incurred relative to total estimated contract costs. An offshore rig construction project typically occurs over a two-year period at the Company’s Vicksburg, Mississippi, shipyard and includes a significant labor cost component for fabrication and assembly. Rowan’s latest offshore rig construction project for an external customer was completed in 2007, and the Company has no such projects currently underway. A rig kit includes selected rig components and parts manufactured over a six- to nine-month period at the Company’s Longview, Texas, facility. Costs are recorded separately for each offshore rig or rig kit project, and by significant activity or component within each project, and include materials issued to the project, labor expenses that are incurred directly for the project and overhead expenses that are allocated across all projects at consistent rates per labor hour. Incurred costs include only those costs that measure project work performed. Material costs incurred, for example, do not include materials purchased but remaining in inventory. Only when such materials have been used in production on a project are they included in incurred project costs. The determination of total estimated project costs is performed monthly based upon then-current information. This process involves an evaluation of progress towards project milestones and an assessment of work left to complete each project activity or component, and is based on physical observations by project managers and engineers. An estimate of project costs is then developed for each significant activity or component based upon the assessment of project status, actual costs incurred to date, and outstanding commitments for project materials and

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services. The Company does not recognize any estimated profit until projects are at least 10% complete, though a full provision is made immediately for any anticipated losses.

The following table summarizes the status of long-term manufacturing contracts in process. Payments, revenues and costs are cumulative from inception of the contract through the date indicated. Payments include those received for contracts in progress or not yet begun and for completed contracts with unpaid amounts outstanding (in thousands):

	December 31,
	2010			2009

Total contract value of long-term contracts in process or not yet begun	$	234,151		$	204,201
Payments received		195,971			119,653
Revenues recognized		201,685			102,155
Costs recognized		125,270			61,407
Payments received in excess of revenues recognized (revenues in excess of payments)		(5,714	)		17,498

Billings in excess of costs and estimated profits on uncompleted contracts (included in current liabilities)	$	7,915		$	25,226
Costs and estimated profits in excess of billings on uncompleted contracts (included in prepaid expenses and other current assets)	$	13,629		$	7,728

Manufacturing service revenues are recognized as the work progresses, and totaled $33.1 million, $22.9 million and $21.1 million in 2010, 2009 and 2008, respectively.

Product Warranties

Rowan’s manufacturing operations offer warranties and parts guarantees extending for stipulated periods of ownership or hours of usage, whichever occurs first. In most cases, dealers of the Company’s products perform the warranty work. For drilling equipment, the Company generally performs warranty work directly and accrues for estimated future warranty costs based on historical experience. Accrued liabilities for product warranties totaled $24.4 million and $10.4 million at December 31, 2010 and 2009, respectively. Net changes to the product warranty liability in 2010 consisted of amounts charged to expense of $30.2 million, reductions of $19.0 million, and other increases of $2.8 million.

Cash Equivalents

Cash equivalents consist of highly liquid temporary cash investments with maturities no greater than three months at the time of purchase.

Accounts Receivable and Allowance for Doubtful Accounts

Inherent in the Company’s revenue recognition policy is the assessment of receivable collectability, and an allowance for uncollectible accounts, recorded as an offset to accounts receivable, is estimated to cover the risk of credit losses. The allowance is based on historical and other factors that predict collectability, including write-offs, recoveries and the monitoring of credit quality. The Company’s allowance for uncollectible accounts was $2.5 million and $3.1 million at December 31, 2010 and 2009, respectively.

Receivables included unreimbursed costs related to the salvage of lost or damaged rigs and related equipment totaling $10.4 million and $29.5 million at December 31, 2010 and 2009, respectively. See Note 7 for additional information regarding the Company’s salvage operations and related insurance reimbursements.

Inventories

Inventories are carried at the lower of average cost or estimated net realizable value. Costs include labor, material and an allocation of production overhead. Management regularly reviews inventory for obsolescence and reserves for items unlikely to be sold in order to reduce the cost to its estimated realizable value. Management determines valuation allowances or reserves for inventory based on historical usage of inventory on hand, assumptions about future demand based on market

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conditions, and estimates about potential alternative uses, which are usually limited. Inventories generally consist of spare parts, work in process, and raw materials to support ongoing manufacturing operations and the Company’s installed base of drilling, mining and timber equipment. Customers rely on the Company to stock these specialized items to ensure that their equipment can be repaired and serviced in a timely manner. The estimated carrying values of inventories therefore ultimately depend on demand driven by oil, natural gas and other commodity prices, general economic conditions worldwide and the potential obsolescence of inventories on hand, among other factors.

In early 2010, the Drilling Products and Systems segment performed an assessment of its Houston-based raw materials and supplies inventories. Management determined that a significant number of items had experienced some level of deterioration such that they were not within tolerance of original specifications or no longer conformed to minimum quality standards. Full provision was made for the cost of items that could not be efficiently reworked. In addition, as the Company continued to work off existing product backlog during the period, the quantity and age of slow-moving inventory items was continuing to grow. Management expected this trend would continue for the foreseeable future. As a result, the Company increased its inventory valuation reserve by approximately $42.0 million and recorded a corresponding charge to expense in the first quarter of 2010.

The following table summarizes the changes in the Company’s inventory reserves for each of the past three years (in thousands):

	Balance, beginning of year		Additions (deductions) charged (credited) to expenses			Other deductions			Balance, end of year
Year ended December 31,
2010	$	42,270	$	47,126		$	(21,354	)	$	68,042
2009		83,700		(6,500	)		(34,900	)		42,300
2008		12,500		72,000			(800	)		83,700

Property and Depreciation

Rowan provides depreciation under the straight-line method from the date an asset is placed into service until it is sold or becomes fully depreciated. The hull, legs and quarters of jack-up rigs are depreciated over 35 years, 30 years, and 25 years, respectively. Related drilling equipment is depreciated over varying lives from 10 to 25 years. Rigs and related equipment are depreciated to salvage values of 20 percent. The resulting weighted average overall life of a newly constructed or acquired jack-up, is approximately 25 years. Lives and salvage values for other assets are presented below:

	Years		Salvage Value

Land drilling equipment	12 to 15			20	%
Drill pipe and tubular equipment		4		10	%

Manufacturing plant and equipment:
Buildings and improvements	10 to 25		10 to 20%
Other equipment	2 to 12		Various

Other property and equipment	3 to 40		various

Expenditures for new property or enhancements to existing property are capitalized and depreciated over the asset’s estimated useful life. Expenditures for maintenance and repairs are charged to operations as incurred. As assets are sold or retired, property cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in results of operations. Rowan capitalizes a portion of interest cost incurred during the construction period. Interest capitalized totaled $40.0 million in 2010, $21.5 million in 2009, and $17.4 million in 2008. Long-lived assets are reviewed for impairment at least annually, or whenever circumstances indicate their carrying amounts may not be recoverable, based upon estimated future cash flows. No impairment charges for long-lived assets were required in 2010, 2009 or 2008.

The amounts of depreciation and amortization expense, capital expenditures and repairs and maintenance expense by operating segment for each of the last three years are presented in Note 11.

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Foreign Currency Transactions

The U.S. dollar is the functional currency for all of Rowan’s operations. Non-U.S. subsidiaries translate their nonmonetary assets at exchange rates prevailing at the time they were acquired; monetary assets and liabilities are translated at year-end rates. Resulting translation gains and losses and foreign currency transaction gains and losses are included in “other income” on the Company’s Consolidated Statements of Income. In order to reduce the impact of exchange rate fluctuations, Rowan generally requires customer payments to be in U.S. dollars and limits foreign currency holdings to the extent they are needed to pay liabilities denominated in such currencies. The Company recognized net foreign currency gains of $4.5 million and $5.4 million in 2010 and 2009, respectively, and a net loss of $10.8 million in 2008, primarily attributable to operations in Australia and Brazil.

Income Taxes

Rowan recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statement and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized. See Note 10 for further information regarding the Company’s income tax assets and liabilities.

Historically, the Company has conducted its foreign operations through U.S. subsidiaries, which resulted in income tax at or near the U.S. statutory rate of 35%. In 2009, the Company began operating many of its foreign-based rigs through its international subsidiaries, and has asserted that such earnings are permanently reinvested abroad. The Company does not provide deferred income taxes on undistributed foreign earnings considered to be permanently invested abroad.

Environmental Costs

Environmental remediation costs are accrued using estimates of future monitoring, testing and clean-up costs where it is probable that such costs will be incurred. Estimates of future monitoring, testing and clean-up costs, and assessments of the probability that such costs will be incurred incorporate many factors, including approved monitoring, testing and/or remediation plans; ongoing communications with environmental regulatory agencies; the expected duration of remediation measures; historical monitoring, testing and clean-up costs, and current and anticipated operational plans and manufacturing processes. Ongoing environmental compliance costs are expensed as incurred, and expenditures to mitigate or prevent future environmental contamination are capitalized. Environmental liabilities at December 31, 2010 and 2009, were not material. See Note 7 for further information regarding the Company’s environmental liabilities.

Income Per Common Share

Basic income per share is computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding during the period. Diluted income per share includes the additional effect of all potentially dilutive securities, which includes nonvested restricted stock and units, dilutive stock options and appreciation rights, and contingently issuable shares such as performance-based stock awards.

A reconciliation of shares for basic and diluted income per share for each of the past three years is set forth below. There were no income adjustments to the numerators of the basic or diluted computations for the periods presented (in thousands):

	Year ended December 31,
	2010		2009		2008

Average common shares outstanding		117,021		113,515		112,632
Add dilutive securities:
Nonvested restricted stock and units		1,270		-		-
Employee and director stock options		417		69		645
Stock appreciation rights and other		110		-		69
Average shares for diluted computations		118,818		113,584		113,346

Options and other potentially dilutive securities are antidilutive and excluded from the dilutive calculations when their exercise or conversion price exceeds the average stock market price during the period. The following table sets forth the share effects of

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securities excluded from the diluted calculations because they were antidilutive for the periods indicated. Such securities could potentially dilute earnings per share in the future (in thousands):

	Year ended December 31,
	2010		2009		2008

Employee and director stock options		153		1,481		63
Stock appreciation rights and other		-		85		-
Total potentially dilutive shares		153		1,566		63

Comprehensive Income

Comprehensive income consists of net income and other comprehensive income (loss). Other comprehensive income (loss) for 2010, 2009 and 2008, consisted solely of adjustments relating to pension and other postretirement benefits, the components of which were as follows, net of income taxes (in thousands):

	Year ended December 31,
	2010			2009			2008

Net (loss) gain arising during the period	$	(3,779	)	$	14,225		$	(126,952	)
Prior service (cost) credit arising during the period		-			43,703			(28	)
Amortization of (gain) loss		12,648			10,721			5,958
Amortization of transition obligation		430			431			430
Amortization of prior service cost (credit)		(4,473	)		(2,385	)		(299	)
Total other comprehensive income (loss), net of tax	$	4,826		$	66,695		$	(120,891	)

See Note 9 for further information regarding the Company’s pension and other postretirement benefits.

New Accounting Standards

There have been no new accounting standards issued that are expected to have a material effect on the Company’s financial statements upon adoption.

NOTE 3 – ACQUISITION OF SKEIE DRILLING & PRODUCTION ASA

On July 1, 2010, the Company entered into a Share Purchase Agreement (the “Purchase Agreement”) with certain shareholders of Skeie Drilling & Production ASA (“SKDP”) and obtained irrevocable commitments from two other shareholders of SKDP (collectively, the “Sellers”) for the purchase of their shares, which constituted 48.8% of the outstanding ordinary shares of SKDP. Under the terms of the Purchase Agreement and irrevocable commitments, the Company agreed to issue 0.00574167 shares of Rowan common stock for each ordinary share of SKDP owned by the Sellers. In July 2010, the Company purchased an additional 1.5% of SKDP shares for cash in the open market.

SKDP, which was subsequently renamed Rowan Drilling Norway AS, was a Norwegian entity that owned and managed the construction of three high-spec jack-up rigs, designated “N-Class,” being designed and built by Keppel FELS Ltd. in Singapore. The first two rigs, the Rowan Viking and Rowan Stavanger, were delivered in October 2010 and January 2011, respectively, and the third rig, which is to be named the Rowan Norway, is expected to be delivered in June 2011. The Company’s remaining obligations under the construction contracts are included in a table of projected cost amounts in Note 7.

In August 2010, the Company issued common stock to certain shareholders of SKDP in private placements in exchange for their SKDP shares and, on August 24, 2010, commenced a tender offer for all remaining ordinary shares of SKDP on the same terms (the “Exchange Offer”). Through the transactions contemplated by the Purchase Agreement, the private placements and the Exchange Offer, the Company acquired approximately 96% of the outstanding SKDP shares. On September 30, 2010, the Company acquired the remaining SKDP shares in cash through a compulsory acquisition pursuant to the Norwegian Public Companies Act. The SKDP shares have since been delisted from the Norwegian OTC System. The

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total consideration paid for all of the SKDP shares was approximately $13 million in cash and 11,724,818 shares of Rowan common stock.

The Company accounted for the acquisition of SKDP as an asset acquisition and allocated the total purchase price to individual assets acquired and liabilities assumed based on relative fair values as of September 10, 2010, (the “Acquisition Date”) with no recognition of goodwill. The net cash effect of the acquisition was a net cash inflow of $201.3 million, including $219.0 million of restricted cash, which the Company used later in 2010 to make the final shipyard payment on the Rowan Viking. Total cost of the acquisition was $402.9 million consisting of (i) $12.9 million for the purchase of SKDP stock, (ii) $39.1 million for open market purchases of SKDP debt, (iii) $13.0 million for legal fees and other transaction costs, and (iv) 11,724,818 shares of Rowan common stock valued at $337.9 million. Net assets acquired consisted of $40.4 million of unrestricted cash, $219.0 million of cash that was restricted under the terms of SKDP’s loan agreement, construction in progress and other assets valued at $683.4 million, and related debt of $539.9 million.

The Acquisition Date was the date upon which the Company’s cumulative ownership interest in SKDP exceeded 50%. Fair values of debt were estimated based on quoted market prices on the Acquisition Date. Shares of Rowan common stock issued were valued based on quoted market prices of Rowan stock on the actual dates of exchange. The results of operations of SKDP have been included in the consolidated financial statements of the Company from the Acquisition Date and were not material.

NOTE 4 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in thousands):

	December 31,
	2010		2009

Compensation and related employee costs	$	100,881	$	110,526
Income taxes		10,847		40,990
Interest		25,962		20,100
Taxes and other		61,148		42,548
Total accrued liabilities	$	198,838	$	214,164

NOTE 5 – LONG-TERM DEBT

Long-term debt consisted of the following (in thousands):

	December 31,
	2010			2009

5.88% Title XI note payable, due March 2012, secured by the Gorilla VI	$	21,361		$	35,613
2.80% Title XI note payable, due October 2013, secured by the Gorilla VII		46,348			61,798
5.0% Senior Notes, due September 2017, net of discount (5.1% effective rate)		398,111			-
4.33% Title XI note payable, due May 2019, secured by the Scooter Yeargain		51,678			57,758
7.875% Senior Notes, due August 2019, net of discount (8.0% effective rate)		497,181			496,852
3.525% Title XI note payable, due May 2020, secured by the Bob Keller		56,779			62,757
3.158% Title XI note payable, due July 2021, secured by the Bob Palmer		114,453			124,859
6.15% Title XI note payable, due July 2010, secured by the Gorilla V		-			7,177
6.94% Title XI note payable, due July 2010, secured by the Gorilla V		-			5,598
Total long-term debt		1,185,911			852,412
Less: Current maturities		(52,166	)		(64,922	)
Long-term debt, excluding current maturities	$	1,133,745		$	787,490

Annual maturities over the next five years are $52.2 million in 2011, $45.0 million in 2012, $37.9 million in 2013, $22.5 million in 2014 and $22.5 million in 2015.

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The Company’s Title XI notes (the “Title XI Notes”) are guaranteed by the U.S. Government under the U.S. Department of Transportation’s Maritime Administration (“MARAD”) Title XI Federal Ship Financing Program. Principal and interest on the Title XI Notes are payable semiannually on various dates throughout the year.

On August 30, 2010, Rowan issued $400 million aggregate principal amount of 5.0% Senior Notes due 2017 (the “5% Senior Notes”), in an SEC registered offering at a price to the public of 99.504% of the principal amount. Net proceeds to the Company, after underwriting discount and offering expenses, were $395.5 million, which we used in 2010 to retire higher-coupon SKDP debt. The 5% Senior Notes will mature on September 1, 2017. Interest on the 5% Senior Notes is payable semi-annually on March 1 and September 1 of each year, beginning March 1, 2011, to the holders of record on the immediately preceding February 15 or August 15, respectively.

The Senior Notes are general unsecured, senior obligations. Accordingly, they rank:

• senior in right of payment to all of the Company’s subordinated indebtedness, if any;

• pari passu in right of payment with any of the Company’s existing and future unsecured indebtedness that is not by its terms subordinated to the Senior Notes, including any indebtedness under the Company’s senior revolving credit facility (other than letter of credit reimbursement obligations that are secured by cash deposits);

• effectively junior to the Company’s existing and future secured indebtedness (including indebtedness under its secured notes issued pursuant to the MARAD Title XI program to finance several offshore drilling rigs), in each case, to the extent of the value of the Company’s assets constituting collateral securing that indebtedness; and

• effectively junior to all existing and future indebtedness and other liabilities of the Company’s subsidiaries (other than indebtedness and liabilities owed to the Company).

The Company may, at its option, redeem any or all of the Senior Notes at any time for an amount equal to 100% of the principal amount to be redeemed plus a make-whole premium and accrued and unpaid interest to the redemption date. The Company may purchase Senior Notes in the open market, or otherwise, at any time without restriction under the indenture. The Company is not required to make mandatory redemption or sinking fund payments with respect to the 5% Senior Notes.

The indenture governing the 5% Senior Notes contains covenants that, among other things, limit the ability of the Company to (a) create liens that secure debt, (b) engage in sale and leaseback transactions and (c) merge or consolidate with another company.

In connection with the acquisition of SKDP, the Company assumed first and second lien bonds of SKDP with a par value of approximately $225 million and $267 million, respectively, as of the Acquisition Date. The first and second lien bonds were revalued and recognized at fair values aggregating $250 million and $279 million, respectively. In the third and fourth quarters of 2010, the Company retired all of the SKDP debt through a combination of open market purchases and redemption, and recognized a net gain on extinguishment of $5.3 million in 2010.

Certain of the SKDP bondholders disputed the Company’s ability to call the debt in 2010; consequently, the Company deposited in escrow with the bond trustee $15.3 million, which is classified as restricted cash on the Company’s Consolidated Balance Sheet at December 31, 2010, to cover interest that would accrue on the first lien bonds until their May 2011 call date, and on the second lien bonds until their respective call dates in February, March and July 2011.

On September 16, 2010, the Company terminated its $155 million revolving credit facility agreement dated June 23, 2008, and entered into a new credit agreement with a group of banks (the “2010 Credit Agreement”) under which the Company may borrow up to $250 million on a revolving basis through September 16, 2014, and up to $350 million on a term basis. The term loan has a final maturity date of September 16, 2015. Term advances are limited to reimbursements for repayments of debt assumed in the SKDP acquisition and must be drawn by July 31, 2011. Interest and commitment fees payable under the 2010 Credit Agreement are based in part on the Company’s then current credit ratings. The annual commitment fee is currently .45% of the unused commitment. Advances would currently bear interest at Libor plus 2.375% per annum. There were no amounts drawn under the 2010 Credit Agreement at December 31, 2010. The 2010 Credit Agreement limits total consolidated indebtedness and contains events of default, the occurrence of which may trigger an acceleration of amounts outstanding under the agreement.

Rowan’s debt agreements contain provisions that require minimum levels of working capital and stockholders’ equity, limit the amount of long-term debt, limit the ability of the Company to create liens that secure debt, engage in sale and leaseback

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transactions, merge or consolidate with another company and, in the event of noncompliance, restrict investment activities and asset purchases and sales, among other things. Additionally, the revolving credit facility agreement provides that the facility will not be available in the event of a material adverse change in the Company’s condition, operations, business, assets, liabilities or ability to perform. The Company was in compliance with each of its debt covenants at December 31, 2010.

Rowan’s debt agreements also specify the minimum insurance coverage for the Company’s financed rigs. The extent of hurricane damage sustained throughout the Gulf Coast area in recent years has dramatically increased the cost and reduced the availability of insurance coverage for windstorm losses. As a result, management has determined that windstorm coverage meeting the requirements of the Company’s existing debt agreements was cost-prohibitive. At the Company’s request, MARAD waived certain windstorm insurance coverage requirements under the loan agreements, for which the Company agreed to a covenant to maintain a minimum cash balance of up to $25 million, which actual amount varies depending on the rig’s location, and is currently $10 million. Rowan remains subject to restrictions on the use of certain insurance proceeds should the Company experience future windstorm losses. Each of these security provisions will be released by MARAD should Rowan be able to obtain windstorm coverage that satisfies the original terms of its debt agreements.

NOTE 6 – FINANCIAL INSTRUMENTS

Fair Values of Financial Instruments

The carrying amounts of the Company’s cash and cash equivalents and trade receivables and payables approximated their fair values due to their short maturity.

Carrying values and fair values of the Company’s debt at December 31, 2010, all of which was fixed-rate, were as follows (amounts in thousands):

	Carrying value		Fair value

5% and 7.875% Senior Notes	$	895,292	$	974,646
Government-guaranteed Title XI Notes		290,619		305,904
	$	1,185,911	$	1,280,550

Concentrations of Credit Risk

Rowan invests its excess cash primarily in time deposits and high-quality money market accounts at several large commercial banks with strong credit ratings, and therefore believes that its risk of loss is minimal.

Approximately 85% of the Company’s revenues are attributable to the Drilling Services and Drilling Products and Services segments, and a substantial portion of the Company’s accounts receivable are from customers in the oil and gas drilling industry. The Company’s drilling customers largely consist of international oil and gas exploration companies and foreign national oil companies; Rowan routinely evaluates the credit quality of potential customers and, with respect to manufacturing operations, may require letters of credit, down payments, milestone payments and/or payment in full prior to shipping in some instances. Rowan’s customers are diversified geographically. One customer provided 11% of consolidated revenues in 2010 and 15% of consolidated revenues in 2009 and 2008. The Company maintains reserves for credit losses and actual losses have been within management’s expectations.

NOTE 7 – COMMITMENTS AND CONTINGENT LIABILITIES

The Company has operating leases covering office space and equipment. Certain of the leases are subject to escalations based on increases in building operating costs. Rental expense under all operating leases was $7.0 million in 2010, $7.1 million in 2009 and $10.9 million in 2008.

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At December 31, 2010, future minimum payments to be made under noncancelable operating leases were as follows (in thousands):

2011	$	6,105
2012		3,876
2013		3,151
2014		2,733
2015		2,276
Later years		9,308
	$	27,449

The following table presents the status of all of the Company’s rigs under construction as of December 31, 2010. Project costs include capitalized interest (in millions):

	Expected or actual delivery date	Total estimated project costs		Total costs incurred through December 31, 2010		Projected costs in 2011		Total future costs

Rowan Stavanger	Jan-11	$	479	$	234	$	245	$	245
Rowan Norway	Jun-11		484		229		255		255
Joe Douglas	Sep-11		246		175		71		71
EXL IV	Dec-11		193		110		83		83
		$	1,402	$	748	$	654	$	654

Rowan periodically employs letters of credit or other bank-issued guarantees in the normal course of its businesses, and had outstanding letters of credit of approximately $70.3 million at December 31, 2010.

Legal Proceedings

During 2005, Rowan lost four offshore rigs, including the Rowan-Halifax, and incurred significant damage on a fifth as a result of Hurricanes Katrina and Rita. The Company had leased the Rowan-Halifax under a charter agreement that commenced in 1984 and was scheduled to expire in March 2008. The rig was insured for $43.4 million, a value that Rowan believes to be more than sufficient to satisfy its obligations under the charter agreement, and by a margin sufficient to cover the $6.3 million carrying value of Rowan equipment installed on the rig. However, the parties holding interests in the rig under the charter claimed that the rig should have been insured for its fair market value and sought recovery from Rowan for compensation above the insured value. Thus, Rowan assumed no insurance proceeds related to the Rowan-Halifax and recorded a charge during 2005 for the full carrying value of its equipment. In November 2005, the Company filed a declaratory judgment action styled Rowan Companies, Inc. vs. Textron Financial Corporation and Wilmington Trust Company as Owner Trustee of the Rowan-Halifax 116-C Jack-Up Rig in the 215th Judicial District Court of Harris County, Texas. The owner interests filed a counterclaim for a variety of relief, claiming a right to payment under the charter based on a post-casualty rig valuation of approximately $83 million. The insurance proceeds were placed in escrow. The district court ultimately granted judgment against Rowan for the difference between (a) what Rowan had already paid to the Owner Trustee out of the escrowed insurance proceeds and (b) that rig valuation. In March 2009, the Court of Appeals for the 14th District of Texas reversed this judgment, holding that the Company’s interpretation of the charter was substantially correct, but directing Rowan to pay additional amounts due under the charter. The Company made this payment out of the escrowed insurance proceeds. In addition, the Court of Appeals remanded the case for further proceedings in the district court to resolve additional issues and to determine the parties’ respective rights to the balance of the escrowed insurance proceeds, which is currently $21.4 million. The owner interests filed a motion for rehearing of the Court of Appeals’ decision. In October 2009, the Court of Appeals denied the motion, but issued a substitute opinion to clarify the scope of the remand. The Court of Appeals again held that the trial court is to resolve issues concerning the proper disposition of excess insurance proceeds. The Court of Appeals further held that the owner interests’ claim that Rowan breached the charter agreement by failing to maintain adequate insurance remains to be decided by the trial court. The owner interests filed another motion for rehearing, which motion was denied in January 2010. In March 2010, the owner interests filed its petition for review in the

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Supreme Court of Texas. The Company believes that no further payment is owed to the opposing parties under the charter and intends to pursue that position vigorously in all subsequent court proceedings.

During 2004, Rowan learned that the Environmental and Natural Resources Division, Environmental Crimes Section of the U.S. Department of Justice (“DOJ”) had begun conducting a criminal investigation of environmental matters involving several of the Company’s offshore drilling rigs, including a rig known as the Rowan-Midland, which at various times operated in the Gulf of Mexico. In 2007, the Company entered into a plea agreement with the DOJ, as amended, under which the Company paid fines and made community service payments totaling $9 million and agreed to be subject to unsupervised probation for a period of three years. The probation period ended in November 2010 without incident.

In January 2008, a civil lawsuit styled State of Louisiana, ex. rel. Charles C. Foti, Jr., Attorney General vs. Rowan Companies, Inc. was filed in U.S. District Court, Eastern District of Texas, Marshall Division, seeking damages, civil penalties and costs and expenses for alleged commission of maritime torts and violations of environmental and other laws and regulations involving the Rowan-Midland and other facilities in areas in or near Louisiana. Subsequently, the case was transferred to U.S. District Court, Southern District of Texas, Houston Division (the “Federal Case”). Thereafter, a similar state civil lawsuit styled State of Louisiana, ex. rel. James D. “Buddy” Caldwell, Attorney General vs. Rowan Companies, Inc. was filed in the 190th Judicial District Court of Harris County, Texas, in February 2010 (the “State Case”). The State Case pleading contains the same legal allegations as the Federal Case except that the State Case involves unidentified Rowan rigs not including the Rowan-Midland. In July 2010, the U.S. District Court dismissed the claims of the plaintiff in the Federal Case and the plaintiff chose not to appeal or otherwise challenge that decision. The State Case was inactive prior to the dismissal of the Federal Case. The Company intends to vigorously defend its position in the State Case and believes it is not probable a loss will be incurred in this matter.

Rowan is involved in various other legal proceedings incidental to its businesses and is vigorously defending its position in all such matters. The Company believes that there are no other known contingencies, claims or lawsuits that could have a material adverse effect on its financial position, results of operations or cash flows.

NOTE 8 – STOCKHOLDERS’ EQUITY

Stock-Based Incentive Plans

Under the 2009 Rowan Companies, Inc. Incentive Plan (the “Plan”), the Compensation Committee of the Company’s Board of Directors is authorized to grant employees and nonemployee directors, through May 2019, incentive awards covering up to 4,500,000 shares of Rowan common stock. The awards may be in the form of stock options, stock appreciation rights, restricted stock awards, restricted stock units, and performance-based awards, in which the number of shares issued is dependent on the achievement of certain long-term market or performance conditions over a specified period. As of December 31, 2010, there were 2,523,946 shares available for future grant under the Plan.

Restricted stock, stock appreciation rights and options granted by the Company generally have multiple vesting dates. The Company recognizes compensation cost for stock-based awards on a straight-line basis over the requisite service period for the entire award. Compensation cost charged to expense under all stock-based incentive awards is presented below (in thousands):

	Year ended December 31,
	2010			2009		2008

Restricted stock and units	$	13,379		$	10,334	$	11,580
Stock appreciation rights		2,678			855		-
Stock options		239			378		1,302
Performance-based awards		(718	)		1,467		2,952
Total compensation cost	$	15,578		$	13,034	$	15,834

Restricted Stock – Restricted stock represents a full share of Rowan common stock issued with a restrictive legend that prevents its sale until the restriction is later removed. In general, the shares vest and the restrictions lapse in one-third increments each year over a three-year service period, or in some cases, cliff vest at the end of a two- or three-year service

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period. The Company measures compensation related to each share based on the market price of the common stock on the date of grant. Restricted stock activity for the year ended December 31, 2010, is summarized below:

	Shares			Weighted-average grant-date fair value per share

Nonvested at January 1, 2010		987,730		$	22.46
Granted		480,401			27.49
Vested		(433,013	)		24.33
Forfeited		(43,489	)		23.73
Nonvested at December 31, 2010		991,629		$	24.01

The fair value of shares vested (measured at the vesting date) in 2010, 2009 and 2008 was $12.6 million, $3.2 million and $6.4 million, respectively. As of December 31, 2010, unrecognized compensation cost for nonvested restricted stock totaled $15.6 million, which is expected to be recognized over a weighted-average period of 1.8 years.

Restricted Stock Units – Restricted stock units (“RSUs”) are rights to receive a specified number of shares of Rowan common stock or an equivalent value in cash. RSUs are typically granted to nonemployee directors and generally cliff vest at the end of a one-year service period; however, shares are not issued until the director terminates service to the Company. The Company measures compensation related to each unit based on the market price of the underlying common stock on the grant date. RSU activity for the year ended December 31, 2010, is summarized below:

	Units		Weighted-average grant-date fair value per share

Outstanding at January 1, 2010		124,934	$	33.84
Granted		45,472		31.34
Outstanding at December 31, 2010		170,406	$	33.17

Vested at December 31, 2010		124,934	$	33.84

In 2009, the Company issued 13,205 shares of common stock with a fair value of $0.3 million in connection with the settlement of vested RSUs. No RSUs were settled in either 2010 or 2008. As of December 31, 2010, unrecognized compensation cost for nonvested RSUs totaled $0.5 million, which is expected to be recognized over a weighted-average period of 0.4 years.

Performance-Based Awards – The Committee may grant awards in which payment is contingent upon the achievement of certain market or performance-based conditions over a period of time specified by the Committee. Payment of such awards may be in Rowan common stock or cash as determined by the Committee. The number of awards granted is expressed as the number of shares that would be issued in the event the “target” goal is attained. The number of shares actually issued may range from zero to 200% of the target share amount.

Performance-based criteria may include total shareholder return (“TSR”), return on investment (“ROI”), or return on capital employed (“ROCE”), among others. Under the TSR criterion, the number of shares that may be issued is based on the Company’s TSR ranking among an industry peer group at the end of the performance period. Fair value is estimated at the grant date using the Monte Carlo simulation model, which considers the probabilities of the Company’s ending TSR at each rank, the number of shares issuable at each rank, and the expected stock price subject to each rank to determine the probability-weighted expected payout. A TSR criterion is deemed a “market condition” under GAAP. Compensation expense for awards with a market condition is reduced only for estimated forfeitures; no adjustment to expense is otherwise made, regardless of the number of shares issued, if any.

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The per-share fair value of awards with ROI or ROCE criteria is equal to the market price of the stock on the date of grant. The Company initially recognized such compensation expense based on the number of shares that would vest in the event the target goal is met, subject to reduction for estimated forfeitures, on a straight-line basis over the performance period. ROI and ROCE criteria are deemed “performance conditions” under GAAP. Compensation expense for awards with performance conditions is remeasured annually based on the Company’s progress towards achieving the target goal and is recognized for only the actual number of shares that vest; in the event such awards do not vest for any reason, all previously recognized expense, if any, would be reversed.

Performance-based award activity for the year ended December 31, 2010, is summarized below:

	Number of shares issuable at target			Weighted-average grant-date fair value per share

Unearned awards outstanding at January 1, 2010		159,416		$	41.08
Granted		-			-
Vested		(24,180	)		37.79
Lapsed, unearned		(50,221	)		37.79
Unearned awards outstanding at December 31, 2010		85,015		$	43.96

Unearned awards outstanding at December 31, 2010, consisted of 85,015 shares (net of 41,985 forfeitures) granted in 2008, under which from zero to 170,030 shares of Rowan common stock will be issued in April 2011 based upon an equal weighting of the Company’s TSR ranking as compared to an industry peer group and its ROCE over the three-year period then ended.

No shares vested in 2009 or 2008 in connection with performance-based awards. As of December 31, 2010, unrecognized compensation cost for outstanding performance-based awards totaled $0.1 million, which is expected to be recognized over a weighted-average period of 0.3 years.

Stock Options and Appreciation Rights – Stock options granted to employees generally become exercisable in one-third or one-quarter annual increments over a three or four-year service period at a price not less than 100% of the market price of the Company’s common stock on the date of grant.

Stock appreciation rights (“SARs”) give the holder the right to receive, at no cost, shares of Rowan common stock, or cash at the discretion of the Committee, equal in value to the excess of the market price of the stock on the date of exercise over the strike price, which is the market price of the stock on the date of grant. SARs granted to employees become exercisable in one-third annual increments over a three-year service period.

Unexercised options and SARs expire ten years after the grant date.

Fair values of options and SARs granted were determined using the Black-Scholes option pricing model with the following weighted-average assumptions. (SARs were granted in only 2010 and 2009; options were granted in only 2008 and prior years):

	2010			2009			2008

Expected life in years		6.0			6.0			5.0
Risk-free interest rate		2.725	%		2.375	%		2.500	%
Expected volatility		50.16	%		52.86	%		48.96	%
Weighted-average grant-date per-share fair value	$	14.00		$	9.03		$	7.01

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Stock option activity for the year ended December 31, 2010, is summarized below:

	Number of shares under option			Weighted-average exercise price		Weighted-average remaining contractual term (in years)		Aggregate intrinsic value (in thousands)

Outstanding at January 1, 2010		1,836,250		$	22.50
Exercised		(350,512	)		19.52
Forfeited or expired		(13,839	)		20.87
Outstanding at December 31, 2010		1,471,899		$	23.23		3.1	$	17,576

Exercisable at December 31, 2010		1,371,899		$	23.81		2.7	$	15,629

The total intrinsic value of options exercised was $3.6 million in 2010, $1.1 million in 2009 and $10.7 million in 2008. As of December 31, 2010, unrecognized compensation cost related to stock options totaled $0.2 million, which is expected to be recognized over a weighted-average period of 1.0 years.

SARs activity for the year ended December 31, 2010, is summarized below:

	Number of shares under SARs			Weighted-average exercise price		Weighted-average remaining contractual term (in years)		Aggregate intrinsic value (in thousands)

Outstanding at January 1, 2010		513,834		$	17.39
Granted		328,362			27.80
Forfeited		(14,011	)		22.51
Outstanding at December 31, 2010		828,185		$	21.43		8.6	$	11,056

Exercisable at December 31, 2010		171,278		$	17.39		8.2	$	2,979

As of December 31, 2010, unrecognized compensation cost related to SARs totaled $5.2 million, which is expected to be recognized over a weighted-average period of 1.8 years.

Limitation on Payments of Dividends

Rowan’s debt agreements contain financial covenants that limit the amount of dividends the Company may distribute to its stockholders. Under the most restrictive of such covenants, approximately $427 million was available for distribution at December 31, 2010. Subject to this and other restrictions, the Board of Directors will determine payment, if any, of future dividends or distributions in light of conditions then existing, including the Company’s earnings, financial condition and cash requirements, opportunities for reinvesting earnings, general business conditions and other factors.

NOTE 9 – PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

Rowan sponsors defined benefit pension plans covering substantially all of its employees, and provides health care and life insurance benefits upon retirement for certain employees.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents the changes in benefit obligations and plan assets during the years indicated and the funded status and weighted-average assumptions used to determine the benefit obligation at each year end (dollars in thousands):

	Year ended December 31, 2010									Year ended December 31, 2009
	Pension benefits			Other benefits			Total			Pension benefits			Other benefits			Total

Benefit obligations:
Balance, January 1	$	532,328		$	81,186		$	613,514		$	562,212		$	80,896		$	643,108
Interest cost		30,713			4,284			34,997			32,477			4,594			37,071
Service cost		14,411			1,955			16,366			15,941			2,040			17,981
Actuarial (gain) loss		31,417			(1,310	)		30,107			9,953			(2,849	)		7,104
Plan amendments		-			-			-			(67,236	)		-			(67,236	)
Plan curtailments		(5,398	)		-			(5,398	)		-			-			-
Benefits paid		(22,142	)		(3,588	)		(25,730	)		(21,019	)		(3,495	)		(24,514	)
Balance, December 31		581,329			82,527			663,856			532,328			81,186			613,514

Plan assets:
Fair value, January 1		337,282			-			337,282			264,189			-			264,189
Actual return		49,535			-			49,535			57,863			-			57,863
Employer contributions		57,265			-			57,265			36,249			-			36,249
Benefits paid		(22,142	)		-			(22,142	)		(21,019	)		-			(21,019	)
Fair value, December 31		421,940			-			421,940			337,282			-			337,282
Net benefit liabilities	$	(159,389	)	$	(82,527	)	$	(241,916	)	$	(195,046	)	$	(81,186	)	$	(276,232	)

Amounts recognized in Consolidated Balance Sheet:
Accrued liabilities	$	(52,735	)	$	(4,510	)	$	(57,245	)	$	(57,265	)	$	(4,510	)	$	(61,775	)
Other liabilities (long-term)		(106,654	)		(78,017	)		(184,671	)		(137,781	)		(76,676	)		(214,457	)
Net benefit liabilities	$	(159,389	)	$	(82,527	)	$	(241,916	)	$	(195,046	)	$	(81,186	)	$	(276,232	)

Net (expense) credit recognized in net benefit cost	$	50,937		$	(69,015	)	$	(18,078	)	$	20,873		$	(65,842	)	$	(44,969	)

Amounts not yet reflected in net periodic benefit cost:
Actuarial loss		(269,690	)		(12,847	)		(282,537	)		(281,959	)		(14,221	)		(296,180	)
Transition obligation		-			(1,324	)		(1,324	)		-			(1,986	)		(1,986	)
Prior service (cost) credit		59,364			659			60,023			66,040			863			66,903
Total accumulated other comprehensive loss		(210,326	)		(13,512	)		(223,838	)		(215,919	)		(15,344	)		(231,263	)
Net benefit liabilities	$	(159,389	)	$	(82,527	)	$	(241,916	)	$	(195,046	)	$	(81,186	)	$	(276,232	)

Weighted-average assumptions:
Discount rate		5.45	%		5.26	%					5.97	%		5.83	%
Rate of compensation increase		4.15	%								4.15	%

The benefit obligations in the preceding table are the projected benefit obligations (PBO). The PBO, as it relates to pension benefits, is the actuarial present value of benefits accrued based on services rendered to date, and includes the estimated effect of future salary increases. The accumulated benefit obligation (ABO) is also based on services rendered to date, but differs from the PBO in that the ABO is based on actual compensation, excluding the effect of future salary increases. The ABO for all pension plans in the aggregate is presented below (in thousands):

	December 31,
	2010		2009

Accumulated benefit obligation	$	581,141	$	523,668

Each of the Company’s pension plans has benefit obligations that exceed the fair value of plan assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Rowan expects that the following amounts, which are classified in accumulated other comprehensive loss, a component of stockholders’ equity, will be recognized as net periodic benefits cost in 2011 (in thousands):

	Pension benefits			Other retirement benefits			Total

Actuarial loss	$	23,268		$	295		$	23,563
Transition obligation		-			662			662
Prior service cost (credit)		(6,678	)		(205	)		(6,883	)
Total amortization	$	16,590		$	752		$	17,342

Effective July 1, 2009, the Company amended the benefit formula for its largest pension plan for active employees who were earning benefits in the plan prior to January 1, 2008. The effect of the change was to reduce 2009 pension expense by approximately $7.3 million, or $0.04 per share net of tax.

The components of net periodic pension cost and the weighted-average assumptions used to determine net cost were as follows (dollars in thousands):

	Year ended December 31,
	2010			2009			2008

Service cost	$	14,411		$	15,941		$	14,392
Interest cost		30,713			32,477			31,599
Expected return on plan assets		(30,640	)		(28,875	)		(29,319	)
Recognized actuarial loss		19,393			16,277			8,901
Amortization of prior service cost		(6,677	)		(3,465	)		(255	)
Net periodic pension cost	$	27,200		$	32,355		$	25,318

Discount rate		5.97	%		6.41	%		6.54	%
Expected return on plan assets		8.00	%		8.00	%		8.00	%
Rate of compensation increase		4.15	%		4.15	%		4.15	%

The components of net periodic cost of other postretirement benefits and the discount rate used to determine net cost were as follows (dollars in thousands):

	Year ended December 31,
	2010			2009			2008

Service cost	$	1,955		$	2,040		$	2,019
Interest cost		4,284			4,594			4,419
Recognized actuarial loss		64			216			265
Amortization of transition obligation		662			662			662
Amortization of prior service cost		(204	)		(204	)		(204	)
Net periodic cost of other postretirement benefits	$	6,761		$	7,308		$	7,161

Discount rate		5.83	%		6.34	%		6.37	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The assumed health care cost trend rates used to measure the expected cost of retirement health benefits was 8.7% for 2011, gradually decreasing to 4.5% for 2029 and thereafter. A one-percentage-point change in the assumed health care cost trend rates would change the reported amounts as follows (in thousands):

	One-percentage-point change
	Increase		Decrease

Effect on total service and interest cost components for the year	$	539	$	(463	)
Effect on postretirement benefit obligation at year-end		5,451		(4,799	)

The pension plans’ investment objectives for fund assets are: to achieve over the life of the plans a return equal the plans’ expected investment return or the inflation rate plus 3%, whichever is greater; to invest assets in a manner such that contributions are minimized and future assets are available to fund liabilities; to maintain liquidity sufficient to pay benefits when due; and to diversify among asset classes so that assets earn a reasonable return with an acceptable level of risk. The plans employ several active managers with proven long-term records in their specific investment discipline.

Target allocations among asset categories and the fair values of each category of plan assets as of December 31, 2010 and 2009, classified by level within the fair value hierarchy (as described in GAAP) is presented below (dollars in thousands). The plans will periodically reallocate assets in accordance with the allocation targets, after giving consideration to the expected level of cash required to pay current benefits and plan expenses:

	Target allocation - % of Plan assets	Target allocation - % of category	Total		Quoted prices in active markets for identical assets (Level 1)		Significant observable inputs (Level 2)		Significant unobservable inputs (Level 3)
December 31, 2010:
Equity securities:	62.5% to 72.5%
S&P 500 Stock Index		14.5% to 24.5%	$	83,993	$	83,993	$	-	$	-
Large cap growth		4% to 14%		39,039		-		39,039		-
Large cap value		4% to 14%		38,565		38,565		-		-
Small cap growth		0% to 10%		23,158		23,158		-		-
Small cap value		0% to 10%		21,340		21,340		-		-
International		10% to 30%		80,151		-		80,151		-
Fixed income:	22.5% to 32.5%
Cash and equivalents		0% to 10%		9,627		1		9,626		-
Aggregate fixed income		10% to 16%		54,393		-		54,393		-
Core plus fixed income		7.5% to 17.5%		51,468		51,468		-		-
Real estate	0% to 10%			20,206		-		20,206		-
Total			$	421,940	$	218,525	$	203,415	$	-

December 31, 2009:
Equity securities:	60% to 80%
S&P 500 Stock Index		15% to 25%	$	63,833	$	63,833	$	-	$	-
Large cap growth		5% to 15%		32,492		-		32,492		-
Large cap value		5% to 15%		31,044		31,044		-		-
Small cap growth		2.5% to 7.5%		15,275		15,275		-		-
Small cap value		2.5% to 7.5%		15,044		15,044		-		-
International		10% to 30%		58,428		-		58,428		-
Fixed income:	20% to 40%					-		-
Cash and equivalents		0% to 10%		10,806		1		10,805		-
Aggregate fixed income		10% to 16%		49,688		-		49,688		-
Core plus fixed income		7.5% to 17.5%		60,672		60,672		-		-
Total			$	337,282	$	185,869	$	151,413	$	-

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Assets in the large cap growth, large cap value, small cap growth, and small cap value categories include investments in common and preferred stocks (and equivalents such as American Depository Receipts and convertible bonds) held through separate accounts, commingled funds and an institutional mutual fund. Assets in the international category include investments in a broad range of international equity securities, including both developed and emerging markets, and are held primarily through a commingled fund. Securities in both the aggregate and “core plus” fixed income categories include U.S. government, corporate, mortgage- and asset-backed securities and Yankee bonds, and both categories target an average credit rating of “A” or better at all times. Individual securities in the aggregate fixed income category must be investment grade or above at the time of purchase, whereas securities in the core plus category may have a rating of “B” or above. Additionally, the core plus category may invest in foreign securities. Assets in the aggregate and core plus fixed income categories are held primarily through a commingled fund and an institutional mutual fund, respectively. The real estate category includes investments in pooled funds whose objectives are diversified equity investments in income-producing properties. Each pooled fund should provide broad exposure to the real estate market by property type, geographic location and size.

To develop the expected long-term rate of return on assets assumption, Rowan considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plans, which was maintained at 8% at December 31, 2010, unchanged from December 31, 2009.

Rowan currently expects to contribute approximately $52.8 million to its pension plans in 2011 and make approximately $4.5 million of direct payments for unfunded other postretirement benefits.

Rowan estimates that the plans will make the following annual payments for pension and other postretirement benefits based upon existing benefit formulas and including amounts attributable to future employee service (in thousands):

	Pension benefits		Other postretirement benefits
Year ended December 31,
2011	$	27,460	$	4,510
2012		29,680		4,710
2013		30,870		4,970
2014		32,680		5,270
2015		34,900		5,680
2016 though 2020		199,770		30,730

Rowan sponsors defined contribution plans covering substantially all employees to which it contributed approximately $11.8 million in 2010, $9.7 million in 2009, and $9.5 million in 2008.

NOTE 10 – INCOME TAXES

The detail of income tax provisions is presented below (in thousands):

	Year ended December 31,
	2010			2009		2008

Current:
Federal	$	25,690		$	52,454	$	148,801
Foreign		34,688			27,530		24,823
State		(700	)		949		(594	)
Total current provision		59,678			80,933		173,030
Deferred		39,344			52,654		53,433
Total provision	$	99,022		$	133,587	$	226,463

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Rowan’s provision for income taxes differs from that determined by applying the federal income tax rate (statutory rate) to income before income taxes, as follows (dollars in thousands):

	Year ended December 31,
	2010			2009			2008

Statutory rate		35	%		35	%		35	%
Tax at statutory rate	$	132,656		$	175,382		$	228,932
Increase (decrease) due to:
State tax expense		(317	)		(95	)		(882	)
Domestic production activities		(6,372	)		(5,619	)		(6,984	)
Research and development tax credit		(325	)		(225	)		(318	)
Extraterritorial income exclusion		-			(25,391	)		-
Foreign companies' operations		(26,092	)		(7,341	)		(292	)
Goodwill		-			-			4,762
Other, net		(528	)		(3,124	)		1,245
Total provision	$	99,022		$	133,587		$	226,463

Temporary differences and carryforwards which gave rise to deferred tax assets and liabilities at December 31, 2010 and 2009, were as follows (in thousands):

	December 31,
	2010					2009
	Current		Noncurrent			Current		Noncurrent

Deferred tax assets:
Accrued employee benefit plan costs	$	16,897	$	53,507		$	17,949	$	62,312
Inventory		16,656		-			9,060		-
Rig relocation operations - net		-		-			9,478		-
U.S. net operating losses		-		109,654			-		100,590
U.K. net operating losses		-		17,778			-		21,112
Other		15,048		11,227			10,580		36,160
Total deferred tax assets		48,601		192,166			47,067		220,174
Less: valuation allowance		-		(17,778	)		-		(21,112	)
Deferred tax assets, net of valuation allowance		48,601		174,388			47,067		199,062

Deferred tax liabilities:
Property, plant and equipment		-		722,254			-		661,400
Other		11,656		3,161			8,996		3,362
Total deferred tax liabilities		11,656		725,415			8,996		664,762
Net deferred tax asset (liability)	$	36,945	$	(551,027	)	$	38,071	$	(465,700	)

At December 31, 2010, the Company had approximately $313.3 million of net operating loss carryforwards in the U.S. expiring in 2028 and 2029. In addition, the Company had a non-expiring net operating loss carryforward in the United Kingdom of approximately $68.4 million against which the Company has provided a full valuation allowance. With the exception of the U.K. net operating loss, management has determined that no valuation allowances were necessary at December 31, 2010 and 2009, as anticipated future tax benefits relating to all recognized deferred income tax assets are expected to be fully realized when measured against a more likely than not standard.

Undistributed earnings of Rowan’s foreign subsidiaries in the amount of approximately $70 million could potentially be subject to additional income taxes of approximately $8 million. The Company has not provided any deferred income taxes on such undistributed foreign earnings because it considers them to be permanently invested abroad.

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Rowan Companies, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

At December 31, 2010, 2009 and 2008, Rowan had $49.9 million, $53.0 million and $3.8 million, respectively, of net unrecognized tax benefits, all of which would reduce the Company’s income tax provision if recognized. The Company does not expect to recognize significant increases or decreases in unrecognized tax benefits during the next twelve months.

The following table highlights the changes in the Company’s gross unrecognized tax benefits during the years ended December 31 (in thousands):

	2010			2009			2008

Gross unrecognized tax benefits - beginning of year	$	55,000		$	7,300		$	5,000
Gross increases - tax positions in prior period		-			37,600			2,300
Gross decreases - tax positions in prior period		(1,300	)		-			-
Gross increases - current period tax positions		-			11,900			-
Settlements		-			-			-
Lapse of statute of limitations		(1,900	)		(1,800	)		-
Gross unrecognized tax benefit - end of year	$	51,800		$	55,000		$	7,300

Interest and penalties relating to income taxes are included in current income tax expense. At December 31, 2010, 2009 and 2008, accrued interest was $0.9 million, $0.7 million and $0.8 million, respectively, and accrued penalties were $0.6 million, $0.4 million and $0.3 million, respectively. To the extent accrued interest and penalties relating to uncertain tax positions are not actually assessed, such accruals will be reversed and the reversals will reduce the Company’s overall income tax provision.

Rowan’s U.S. federal tax returns for 2006 through 2008 are currently under audit by the Internal Revenue Service (“IRS”), and 2002 and later years remain subject to examination. Various state tax returns for 2005 and subsequent years remain open for examination. In the Company’s foreign tax jurisdictions, returns for 2007 and subsequent years remain open for examination. Rowan is undergoing other routine tax examinations in various foreign, U.S. federal, state and local taxing jurisdictions in which the Company has operated. These examinations cover various tax years and are in various stages of finalization. Rowan believes that any income taxes ultimately assessed by any foreign, U.S. federal, state or local taxing authorities will not materially exceed amounts for which the Company has already provided.

In 2009, the Company recognized a $25.4 million tax benefit as a result of applying the facts of a third-party tax case to the Company’s situation. That case provided a more favorable tax treatment for certain foreign contracts entered into in prior years. The Company has deferred recognition of a remaining $49.2 million estimated benefit in accordance with the accounting guidelines for income tax uncertainties. In connection with the above, the Company has recorded a long-term receivable, which is included in other assets on the Condensed Consolidated Balance Sheet at December 31, 2010 and 2009, for the gross claim of approximately $74.6 million and a long-term liability of approximately $49.2 million.

Income from continuing operations before income taxes consisted of domestic entities’ earnings of $260.3 million, $558.3 million, and $597.1 million in 2010, 2009, and 2008, respectively, foreign entities’ earnings of $118.7 million in 2010, a foreign entities’ loss of $57.2 million in 2009, and foreign entities’ earnings of $56.9 million in 2008.

NOTE 11 – SEGMENT INFORMATION

Rowan has three principal business segments – Drilling Services, Drilling Products and Systems, and Mining, Forestry and Steel Products. The Drilling Services segment provides onshore and offshore oil and gas contract drilling services on a daily rate basis. The Drilling Products and Systems segment manufactures equipment and parts for the oil and gas drilling industry featuring jack-up rigs, rig kits and related components and parts, mud pumps, drawworks, top drives, rotary tables, other rig equipment, variable-speed motors, drives and other electrical components. The Mining, Forestry and Steel Products segment manufactures large-wheeled mining and timber equipment and related parts, and carbon and alloy steel and steel plate. The Drilling Products and Systems and Mining, Forestry and Steel Products segments operate under LeTourneau.

Rowan’s reportable segments reflect an aggregation of separately managed, strategic business units for which financial information is separately prepared and monitored based upon qualitative and quantitative factors. The Company evaluates segment performance based on income from operations.

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Rowan Companies, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Refer to Note 2 for further information with regard to significant accounting policies applicable to the Company’s business segments.

Certain segment information is set forth below (in thousands):

	Drilling Services		Drilling Products and Systems			Mining, Forestry and Steel Products		Eliminations			Consolidated

2010:
Revenues from external customers	$	1,208,766	$	310,359		$	300,082	$	-		$	1,819,207
Intersegment revenues		-		204,976			3		(204,979	)		-
Income from operations		389,909		(16,341	)		64,991		(47,603	)		390,956
Depreciation and amortization		176,065		8,596			7,783		(5,881	)		186,563
Repairs and maintenance		104,106		8,705			10,731		-			123,542
Material charges		-		42,024			-		-			42,024
Capital expenditures		481,467		4,493			4,600		-			490,560
Total assets (at end of year)		5,601,287		401,727			214,443		-			6,217,457

2009:
Revenues from external customers	$	1,214,896	$	369,371		$	185,913	$	-		$	1,770,180
Intersegment revenues		-		278,892			-		(278,892	)		-
Income from operations		466,961		99,973			25,504		(91,425	)		501,013
Depreciation and amortization		157,519		9,013			6,510		(1,597	)		171,445
Repairs and maintenance		92,745		8,555			10,508		-			111,808
Material charges		-		-			-		-			-
Capital expenditures		587,237		460			9,003		-			596,700
Total assets (at end of year)		4,527,435		474,768			208,491		-			5,210,694

2008:
Revenues from external customers	$	1,451,623	$	493,456		$	267,657	$	-		$	2,212,736
Intersegment revenues		-		382,893			-		(382,893	)		-
Income from operations		666,803		30,595			32,569		(71,844	)		658,123
Depreciation and amortization		125,907		9,461			6,073		(46	)		141,395
Repairs and maintenance		108,143		14,458			13,602		-			136,203
Material charges 1		24,635		81,841			4,695		-			111,171
Capital expenditures		817,276		9,632			6,238		-			833,146
Total assets (at end of year)		3,714,289		583,055			251,548		-			4,548,892

_____________________________________

1 See Note 12 for an analysis of material charges.

One customer provided 11% of consolidated revenues in 2010 and 15% of consolidated revenues in 2009 and 2008.

The classifications of revenues and assets among geographic areas in the tables which follow were determined based on the physical location of assets. Because the Company’s offshore drilling rigs are mobile, classifications by area are dependent on the rigs’ location at the time revenues are earned, and may vary from one period to the next.

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Rowan Companies, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Revenues by geographic area are set forth below (in thousands):

	2010		2009		2008

United States	$	1,007,446	$	952,023	$	1,331,214
Saudi Arabia		207,131		280,187		347,624
Norway		112,488		25,783		-
Canada		79,494		57,337		-
Qatar		78,819		98,875		138,641
Egypt		71,811		12,019		-
Angola		68,543		115,992		117,466
United Kingdom		67,340		146,827		166,486
Australia		58,343		58,581		69,144
Mexico		45,633		14,101		-
Brazil		18,959		5,715		-
Trinidad		-		-		41,522
Other		3,200		2,740		639
Consolidated revenues	$	1,819,207	$	1,770,180	$	2,212,736

Long-lived assets by geographic area are set forth below (in thousands):

	December 31,
	2010		2009		2008

United States	$	1,488,663	$	1,556,183	$	1,583,242
Rigs under construction		937,609		528,669		425,182
United Kingdom		822,335		387,546		371,830
Saudi Arabia		743,002		535,448		505,358
Trinidad		204,432		-		-
Norway		202,773		-		-
Egypt		200,551		214,814		-
Qatar		91,735		49,390		49,000
Mexico		54,307		56,032		-
Canada		43,571		40,553		178
Australia		2,848		6,948		4,093
Angola		-		202,290		208,626
Other		1,611		1,612		19
Consolidated long-lived assets	$	4,793,437	$	3,579,485	$	3,147,528

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Rowan Companies, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 12 – MATERIAL CHARGES AND OTHER OPERATING EXPENSES

Operating expenses in 2010 includes a $42.0 million charge to results of Drilling Products and Systems’ operations for an adjustment to the Company’s manufacturing inventory valuation reserve. See “Inventories” in Note 2 for further information.

Operating expenses for the fourth quarter of 2008 included the following adjustments, by operating segment (in thousands):

	Drilling Services		Drilling Products and Systems		Mining, Forestry and Steel Products		Consolidated

Termination of construction of fourth 240C rig	$	11,830	$	-	$	-	$	11,830
Severance and retirement costs		8,531		2,248		-		10,779
Suspension of LeTourneau monetization process		2,781		6,338		3,445		12,564
Goodwill impairment		1,493		10,863		1,250		13,606
Increase in inventory valuation reserve		-		62,392		-		62,392
	$	24,635	$	81,841	$	4,695	$	111,171

NOTE 13 – RELATED PARTY TRANSACTIONS

A Rowan director served as managing director of an investment bank until his departure from the bank in March 2009. Rowan paid the investment bank $1.8 million in 2009 for services provided in connection with the Company’s July 2009 Senior Note offering and $4.1 million for services in 2008.

Another Rowan director serves as “of counsel” to a law firm that represents Rowan on certain matters and to which the Company paid approximately $0.4 million, $0.6 million, and $1.6 million for legal fees and expenses in 2010, 2009 and 2008, respectively.

In each case, the director’s services were approved by the Company’s Board of Directors, and compensation from his employer was not tied to amounts received from the Company. Rowan believes that the fees paid for services reflected market rates.

NOTE 14 – SUPPLEMENTAL CASH FLOW INFORMATION

Noncash investing and financing activities excluded from the Consolidated Statements of Cash Flows and other supplemental cash flow information follows (in thousands):

	Years ended December 31,
	2010		2009			2008

Value of common stock issued in exchange for SKDP shares	$	337,907	$	-		$	-
Accrued but unpaid additions to property and equipment at December 31		40,345		23,340			4,157
Cash interest payments in excess of (less than) interest capitalized		23,596		(7,568	)		3,930
Cash income tax payments, net of refunds		98,979		137,648			150,660

Interest capitalized in 2009 exceeded the amount of interest payments due to the timing of the first interest payment on the 7.875% Senior Notes, which were issued in July 2009. Interest on the Senior Notes is payable each February and August beginning February 2010.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Rowan Companies, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Rowan Companies, Inc. and subsidiaries (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, comprehensive income, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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 consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

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, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2011, expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 1, 2011

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Rowan Companies, Inc.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Rowan is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition.

We are required to assess the effectiveness of our internal controls relative to a suitable framework. The Committee of Sponsoring Organizations of the Treadway Commission (COSO) developed a formalized, organization-wide framework that embodies five interrelated components — the control environment, risk assessment, control activities, information and communication and monitoring, as they relate to three internal control objectives — operating effectiveness and efficiency, financial reporting reliability and compliance with laws and regulations.

Our assessment included an evaluation of the design of our internal control over financial reporting relative to COSO and testing of the operational effectiveness of our internal control over financial reporting. Based upon our assessment, we have concluded that our internal controls over financial reporting were effective as of December 31, 2010.

The registered public accounting firm Deloitte & Touche LLP has audited Rowan’s consolidated financial statements included in our 2010 Annual Report on Form 10-K and has issued an attestation report on the Company’s internal control over financial reporting.

/s/ W. MATT RALLS	/s/ W. H. WELLS
W. Matt Ralls	W. H. Wells
President and Chief Executive Officer	Senior Vice President, Chief Financial Officer and Treasurer


March 1, 2011	March 1, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Rowan Companies, Inc.

Houston, Texas

We have audited the internal control over financial reporting of Rowan Companies, Inc. and subsidiaries (the "Company") as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, 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, 2010, 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 as of and for the year ended December 31, 2010 of the Company and our report dated March 1, 2011, expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 1, 2011

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SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Unaudited quarterly financial data for each full quarter within the two most recent fiscal years follows (in thousands except per share amounts):

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
2010:
Revenues	$	432,405	$	490,036	$	437,946	$	458,820
Income from operations		98,104		130,357		88,250		74,245
Net income		64,623		90,916		67,171		57,285

Per share amounts:
Net income — Basic	$	0.57	$	0.80	$	0.58	$	0.46
Net income — Diluted		0.56		0.79		0.57		0.45

2009:
Revenues	$	494,808	$	482,160	$	393,421	$	399,791
Income from operations		198,245		130,543		87,088		85,137
Net income		131,700		96,583		78,392		60,829

Per share amounts:
Net income — Basic	$	1.16	$	0.85	$	0.69	$	0.53
Net income — Diluted		1.16		0.85		0.69		0.53

The sum of the per-share amounts for the quarters may not equal the per-share amounts for the full year since the quarterly and full year per share computations are made independently.

The first quarter of 2010 includes a $42.0 million charge to operations for an inventory valuation reserve adjustment recorded by the Drilling Products and Systems manufacturing segment. The adjustment resulted from an assessment of the segment’s Houston-based raw materials and supplies inventory. See “Inventories” in Note 2 of Notes to Consolidated Financial Statements for further information.

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

None

ITEM 9A. CONTROLS AND PROCEDURES

The Company’s management has evaluated, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, the effectiveness of the Company’s disclosure controls and procedures, as of the end of the period covered by this report, pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Company’s Chief Executive Officer, along with the Company’s Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2010.

Our management is responsible for establishing and maintaining internal control over financial reporting (ICFR). Our internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations, and therefore can only provide reasonable assurance with respect to financial statement preparation and presentation.

Our management’s assessment is that the Company did maintain effective ICFR as of December 31, 2010, within the context of the framework established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and that the Company did not have a material change in ICFR during the fourth quarter of 2010.

See “Management’s Report on Internal Control over Financial Reporting” included in Item 8 of this Form 10-K.

ITEM 9B. OTHER INFORMATION

Not applicable

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information concerning our directors will appear in our Proxy Statement for the 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2011, under the caption “Election of Directors.” Such information is incorporated herein by reference.

Information concerning our executive officers appears in Part 1 under the caption “Executive Officers of the Registrant” of this Form 10-K.

Information concerning our Audit Committee will appear in our Proxy Statement for the 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2011, under the caption “Committees of the Board of Directors.” Such information is incorporated herein by reference.

Information concerning compliance with Section 16(a) of the Securities Exchange Act will appear in our Proxy Statement for the 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A of the Exchange Act (“Regulation 14A”) on or before March 15, 2011, under the caption “Additional Information - Section 16(a) Beneficial Ownership Reporting Compliance.” Such information is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

Information concerning director and executive compensation will appear in our Proxy Statement for the 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2011, under the captions “Director Compensation and Attendance,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” and “Executive Compensation.” Such information is incorporated herein by reference.

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

Information concerning the security ownership of management will appear in our Proxy Statement for the 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2011, under the caption “Security Ownership of Certain Beneficial Owners and Management.” Such information is incorporated herein by reference.

The business address of all directors is the principal executive offices of the Company as set forth on the cover page of this Form 10-K.

Equity Compensation Plan Information

The following table provides information about our common stock that may be issued under equity compensation plans as of December 31, 2010.

	Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	Weighted-average exercise price of outstanding options, warrants and rights (2)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)



Equity compensation plans approved by security holders	1,876,687	$22.57	2,523,946
Equity compensation plans not approved by security holders	-	-	-
Total	1,876,687	$22.57	2,523,946

(1)	The number of securities to be issued includes (i) 1,471,899 options and 319,773 shares issuable under outstanding SARs (see note (2) below) and (ii) 85,015 contingent shares in connection with performance-based stock awards. The exact number of shares to be issued under performance-based awards is dependent on meeting certain market-based or performance-based criteria and can range between zero and 170,030 shares. See Note 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for a further discussion of performance-based stock awards.

(2)	The weighted-average exercise price in column (b) is based on (i) 1,471,899 shares under outstanding options with a weighted average exercise price of $23.23 per share, and (ii) 319,773 shares of stock that would be issuable in connection with 828,185 stock appreciation rights (SARs) outstanding at December 31, 2010. The number of shares issuable under SARs is equal in value to the excess of the Rowan stock price on the date of exercise over the exercise price. The number of shares under SARs included in column (a) was based on a December 31, 2010 closing stock price of $34.91 and a weighted-average exercise price of $21.43 per share.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information concerning director and executive related party transactions will appear in our Proxy Statement for the 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before March 15, 2011, within the section and under the captions “Director Independence” and “Related Party Transactions.” Such information is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information concerning principal accounting fees and services will appear in our Proxy Statement for the 2011 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A no later than April 30, 2011, in the last paragraph under the caption “Fees of Audit Firm.” Such information is incorporated herein by reference.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Index to Financial Statements, Financial Statement Schedules and Exhibits

(1) Financial Statements

See Item 8, “Financial Statements and Supplementary Data,” beginning on page 42 of this Form 10-K for a list of financial statements filed as a part of this report.

(2) Financial Statement Schedules

Financial Statement Schedules I, II, III, IV, and V are not included in this Form 10-K because such schedules are not required, the required information is not significant, or the information is presented elsewhere in the financial statements.

(3) Exhibits

Unless otherwise indicated below as being incorporated by reference to another filing of the Company with the Securities and Exchange Commission, each of the following exhibits is filed herewith:

3.1	Restated Certificate of Incorporation of the Company, dated February 17, 1984 (incorporated by reference to Exhibit 4.1 to Registration Statement No. 333-84369 on Form S-8) and the Certificates of Designation for the Company’s Series A Preferred Stock (and Certificate of Correction related thereto) (incorporated by reference to Exhibit 4.8 to Registration Statement No. 333-84369 on Form S-8), Series B Preferred Stock (incorporated by reference to Exhibit 4d to Form 10-K for the year ended December 31, 1999), Series D Preferred Stock (incorporated by reference to Exhibit 4.11 to Registration Statement No. 333-82804 on Form S-3 filed on February 14, 2002), and Series E Preferred Stock (incorporated by reference to Exhibit 4.12 to Registration Statement No. 333-82804 on Form S-3 filed on February 14, 2002) and as amended by the Certificate of Amendment to Restated Certificate of Incorporation of Rowan Companies, Inc. dated April 29, 2010 (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K dated April 29, 2010).
3.2	Amended and Restated Bylaws of Rowan Companies, Inc., effective as of April 29, 2010, incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K dated April 29, 2010 (File No. 1-5491).
4.1	Certificate of Change of Address of Registered Office and of Registered Agent dated July 25, 1984, incorporated by reference to Exhibit 4.4 to Registration Statement No. 333-84369 on Form S-8 (File No. 1-5491).
4.2	Certificate of Amendment of Certificate of Incorporation dated April 24, 1987, incorporated by reference to Exhibit 4.5 to Registration Statement No. 333-84369 on Form S-8 (File No. 1-5491).
4.3	Specimen Common Stock certificate, incorporated by reference to Exhibit 4k to Form 10-K for the year ended December 31, 2001 (File No. 1-5491).
4.4	Indenture for Senior Debt Securities dated as of July 21, 2009, between Rowan Companies, Inc. and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated July 21, 2009 (File No. 1-5491).
4.5	First Supplemental Indenture dated as of July 21, 2009, between Rowan Companies, Inc. and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated July 21, 2009 (File No. 1-5491).
4.6	Second Supplemental Indenture dated as of August 30, 2010, between Rowan Companies, Inc. and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on August 30, 2010 (File No. 1-5491).
4.7	Form of 5% Senior Note due 2017 (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on August 30, 2010).
10.1	Restated 1988 Nonqualified Stock Option Plan, incorporated by reference to Appendix C to the Notice of Annual Meeting and Proxy Statement dated March 20, 2002 (File No. 1-5491) and Form of Stock Option Agreement related thereto, incorporated by reference to Exhibit 10c to Form 10-K for the year ended December 31, 2004 (File No. 1-5491).

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10.2	1998 Nonemployee Director Stock Option Plan, incorporated by reference to Exhibit 10b of Form 10-Q for the quarter ended March 31, 1998 (File No. 1-5491) and Form of Stock Option Agreement related thereto, incorporated by reference to Exhibit 10c to Form 10-K for the year ended December 31, 2004 (File No. 1-5491).
10.3	2009 Rowan Companies, Inc. Incentive Plan, incorporated by reference to Appendix A of the Company’s definitive proxy statement dated March 19, 2009 (File No. 1-5491) and Form of 2009 Stock Appreciation Right Agreement, Form of 2009 Restricted Stock Agreement, and Form of Non-Employee Director 2009 Restricted Stock Unit Agreement under the 2009 Rowan Companies, Inc. Incentive Plan, incorporated by reference to Exhibits 10.2, 10.3 and 10.4, respectively, of the Company’s Quarterly Report on Form 10-Q dated August 10, 2009 (File No. 1-5491).
10.4	Pension Restoration Plan of LeTourneau Technologies, Inc., a wholly owned subsidiary of the Company, incorporated by reference to Exhibit 10j to Form 10-K for the year ended December 31, 1994 (File No. 1-5491).
10.5	Participation Agreement dated December 1, 1984 between Rowan and Textron Financial Corporation et al. and Bareboat Charter dated December 1, 1984 between Rowan and Textron Financial Corporation et al., incorporated by reference to Exhibit 10c to Form 10-K for the year ended December 31, 1985 (File No. 1-5491).
10.6	Election and acceptance letters with respect to the exercise of the Fixed Rate Renewal Option set forth in the Bareboat Charter dated December 1, 1984 between Rowan and Textron Financial Corporation et al, incorporated by reference to Exhibit 10j to Form 10-K for the year ended December 31, 1999 (File No. 1-5491).
10.7	Commitment to Guarantee Obligations dated September 29, 1998 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla VI), incorporated by reference to Exhibit 10a to Form 10-Q for quarter ended September 30, 1998 (File No. 1-5491).
10.8	Credit Agreement and Trust Indenture both dated September 29, 1998 between Rowan and Citibank, N.A. (relating to Gorilla VI), incorporated by reference to Exhibit 10b to Form 10-Q for the quarter ended September 30, 1998 (File No. 1-5491).
10.9	Amendment No. 1 dated March 15, 2001 to Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla VI), incorporated by reference to Exhibit 10v to Form 10-K for the year ended December 31, 2000 (File No. 1-5491).
10.10	Supplement No. 1 dated March 15, 2001 to Trust Indenture between Rowan and Citibank, N.A. (relating to Gorilla VI), incorporated by reference to Exhibit 10v to Form 10-K for the year ended December 31, 2000 (File No. 1-5491).
10.11	Commitment to Guarantee Obligations dated October 29, 1999 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla VII), incorporated by reference to Exhibit 10v to Form 10-K for the year ended December 31, 1999 (File No. 1-5491).
10.12	Credit Agreement and Trust Indenture both dated October 29, 1999 between Rowan and Citibank, N.A. (relating to Gorilla VII), incorporated by reference to Exhibit 10w to Form 10-K for the year ended December 31, 1999 (File No. 1-5491).
10.13	Amendment No. 1 dated June 30, 2003 to the Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to Gorilla VII), incorporated by reference to Exhibit 10x to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.14	Supplement No. 1 dated June 30, 2003 to Trust Indenture between Rowan and Citibank, N.A. (relating to Gorilla VII), incorporated by reference to Exhibit 10y to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.15	Commitment to Guarantee Obligations dated May 23, 2001 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Bob Palmer, formerly Gorilla VIII), incorporated by reference to Exhibit 10y to Form 10-K for the year ended December 31, 2001 (File No. 1-5491).
10.16	Credit Agreement and Trust Indenture both dated May 23, 2001 between Rowan and Citibank, N.A. (relating to the Bob Palmer, formerly Gorilla VIII), incorporated by reference to Exhibit 10z to Form 10-K for the year ended December 31, 2001 (File No. 1-5491).
10.17	Commitment to Guarantee Obligations dated May 28, 2003 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Scooter Yeargain), incorporated by reference to Exhibit 10bb to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).

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10.18	Credit Agreement and Trust Indenture both dated May 28, 2003 between Rowan and Citibank, N.A. (relating to the Scooter Yeargain), incorporated by reference to Exhibit 10cc to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.19	Amendment No. 1 dated June 15, 2005 to the Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Scooter Yeargain), incorporated by reference to Exhibit 10a to Form 10-Q for the quarterly period ended June 30, 2005 (File No. 1-5491).
10.20	Supplement No. 1 dated June 15, 2005 to Trust Indenture between Rowan and Citibank, N.A. (relating to the Scooter Yeargain), incorporated by reference to Exhibit 10b to Form 10-Q for the quarterly period ended June 30, 2005 (File No. 1-5491).
10.21	Commitment to Guarantee Obligations dated May 28, 2003 and First Preferred Ship Mortgage between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10dd to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.22	Credit Agreement and Trust Indenture both dated May 28, 2003 between Rowan and Citibank, N.A. (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10ee to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
10.23	Amendment No. 1 dated March 28, 2005 to Credit Agreement between Rowan and Citibank, N.A. (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10a to Form 10-Q for the quarterly period ended March 31, 2005 (File No. 1-5491).
10.24	Amendment No. 2 dated May 4, 2005 to Credit Agreement between Rowan and Citibank, N.A. (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10b to Form 10-Q for the quarterly period ended March 31, 2005 (File No. 1-5491).
10.25	Memorandum Agreement dated January 26, 2006 between Rowan and C. R. Palmer, incorporated by reference to Exhibit 10jj to Form 10-K for year ended December 31, 2005 (File No. 1-5491).
10.26	2005 Rowan Companies, Inc. Long-Term Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K filed May 10, 2005 (File No. 1-5491) and Form of Non-Employee Director 2005 Restricted Stock Unit Grant, Form of Non-Employee Director 2006 Restricted Stock Unit Grant, Form of 2005 Restricted Stock Grant Agreement, Form of 2005 Nonqualified Stock Option Agreement, Form of 2005 Performance Share Award Agreement related thereto, each incorporated by reference to Exhibits 10c, 10d, 10e, 10f and 10g, respectively, to Form 10-Q for the quarterly period ended June 30, 2005 (File No. 1-5491).
10.27	Change in Control Agreement and Change in Control Supplement, incorporated by reference to Exhibits 10.1 and 10.2 to Form 8-K filed December 20, 2007 (File 1-5491).
10.28	Amendment No. 1 dated August 4, 2009, to the Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q filed August 10, 2009 (File No. 1-5491).
10.29	Supplement No. 2 dated August 4, 2009, to Trust Indenture between Rowan and Citibank, N.A. (relating to the Bob Keller, formerly Tarzan II), incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed August 10, 2009 (File No. 1-5491).
10.30	Form of Indemnification Agreement between Rowan Companies, Inc. and each of its directors and certain officers, incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 2, 2009 (File No. 1-5491).
10.31	Amendment No. 1 dated November 24, 2009, to the Commitment to Guarantee Obligations between Rowan and the Maritime Administration of the U.S. Department of Transportation (relating to the Bob Palmer, formerly Gorilla VIII), incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 24, 2009 (File No. 1-5491).
10.32	Supplement No. 2 dated November 24, 2009, to Trust Indenture between Rowan and Manufacturers and Traders Trust Company (relating to the Bob Palmer, formerly Gorilla VII), incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K dated November 24, 2009 (File No. 1-5491).
10.33	Restoration Plan of Rowan Companies, Inc. (As Restated Effective July 1, 2009), incorporated by reference to Exhibit 10.43 to Form 10-K for the year ended December 31, 2009 (File No. 1-5491).

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10.34	Share Purchase Agreement dated July 1, 2010, among Rowan Companies, Inc., Skeie Technology AS, Skeie Tech Invest AS and Wideluck Enterprises Limited and Pre-Acceptance Letters from Skeie Holding AS and Trafalgar AS, each relating to the purchase of shares of common stock of Skeie Drilling & Production ASA (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on August 19, 2010).
10.35	Credit Agreement dated September 16, 2010, among Rowan Companies, Inc., as Borrower, the Lenders named therein, Wells Fargo Bank, National Association, as Administrative Agent, Issuing Lender and Swingline Lender and Citibank, N.A., DnB Nor Bank ASA and Royal Bank of Canada, as Co-Syndication Agents (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on September 16, 2010).
10.36	Bond Agreement between SKDP 1 Ltd and Norsk Tillitsmann ASA dated May 14, 2010 relating to 12.0% Senior Secured Callable Bond Issue 2010/2017, as amended (incorporated by reference to Exhibit 10.1 of Amendment No. 1 to the Company’s Current Report on Form 8-K filed on November 5, 2010).
10.37	Amended and Restated Agreement to the Loan Agreement between SKDP and Norsk Tillitsmann ASA dated July 15, 2009, relating to 11.25 % Skeie Drilling & Production ASA Callable Bond Issue due 2007/2013, guaranteed by SKDP 1 Ltd (incorporated by reference to Exhibit 10.2 of Amendment No. 1 to the Company’s Current Report on Form 8-K filed on November 5, 2010).
10.38	Amended and Restated Agreement to the Loan Agreement between SKDP and Norsk Tillitsmann ASA dated July 15, 2009, relating to 11.25 % Skeie Drilling & Production ASA Callable Bond Issue due 2007/2013, guaranteed by SKDP 2 Ltd (incorporated by reference to Exhibit 10.3 of Amendment No. 1 to the Company’s Current Report on Form 8-K filed on November 5, 2010).
10.39	Amended and Restated Agreement to the Loan Agreement between SKDP and Norsk Tillitsmann ASA dated July 15, 2009, relating to 11.25 % Skeie Drilling & Production ASA Callable Bond Issue due 2007/2013, guaranteed by SKDP 3 Ltd (incorporated by reference to Exhibit 10.4 of Amendment No. 1 to the Company’s Current Report on Form 8-K filed on November 5, 2010).
10.40	LeTourneau Technologies, Inc. Incentive Plan, effective January 1, 2011, Form of 2011 Stock Appreciation Right Notice, and Form of 2011 Performance Restricted Stock Unit Notice.
14	Code of Business Conduct for Senior Financial Officers of the Company, incorporated by reference to Exhibit 14 to Form 10-K for the year ended December 31, 2003 (File No. 1-5491).
21	Subsidiaries of the Registrant as of January 11, 2011.
23	Consent of Independent Registered Public Accounting Firm.
24	Powers of Attorney pursuant to which names were affixed to this Form 10-K for the year ended December 31, 2010.
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99	Annual CEO Certification to the New York Stock Exchange.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

__________

*	Only portions specifically incorporated herein are deemed to be filed.

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EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS

Compensatory plans in which Rowan’s directors and executive officers participate are listed as follows:

•

Restated 1988 Nonqualified Stock Option Plan, incorporated by reference to Appendix C to the Notice of Annual Meeting and Proxy Statement dated March 20, 2002 (File No. 1-5491).

•

1998 Nonemployee Director Stock Option Plan, incorporated by reference to Exhibit 10b of Form 10-Q for the quarter ended March 31, 1998 (File No. 1-5491).

•

Restoration Plan of Rowan Companies, Inc. (As Restated Effective July 1, 2009), incorporated by reference to Exhibit 10.43 to Form 10-K for the year ended December 31, 2009 (File No. 1-5491).

•

Pension Restoration Plan of LeTourneau, Inc., a wholly owned subsidiary of the Company, incorporated by reference to Exhibit 10j to Form 10-K for the year ended December 31, 1994 (File No. 1-5491).

•

2005 Long-Term Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K filed May 10, 2005 (File No. 1-5491).

•

Change in Control Agreement and Change in Control Supplement for the Rowan Companies, Inc. Restated 1988 Nonqualified Stock Option Plan and the 2005 Rowan Companies, Inc. Long-Term Incentive Plan incorporated by reference to Exhibits 10.1 and 10.2 to Form 8-K filed December 20, 2007 (File 1-5491).

•

2009 Rowan Companies, Inc. Incentive Plan, incorporated by reference to Appendix A of the Company’s definitive proxy statement dated March 19, 2009 (File No. 1-5491).

•

LeTourneau Technologies, Inc. Incentive Plan, effective January 1, 2011, Form of 2011 Stock Appreciation Right Notice, and Form of 2011 Performance Restricted Stock Unit Notice (filed herewith).

Rowan agrees to furnish to the Commission upon request a copy of all instruments defining the rights of holders of long-term debt of the Company and its subsidiaries.

For the purposes of complying with the amendments to the rules governing Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the undersigned registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into Registrant’s Registration Statements on Form S-8 Nos. 2-58700, as amended by Post-Effective Amendment No. 4 (filed June 11, 1980), 33-33755, as amended by Amendment No. 1 (filed March 29, 1990), 33-61444 (filed April 23, 1993), 333-84369 (filed August 3, 1999), 333-84405 (filed August 3, 1999), 333-101914 (filed December 17, 2002), 333-132762 (filed March 28, 2006), and 333-158985 (filed May 5, 2009):

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the act and will be governed by the final adjudication of such issue.

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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.

		ROWAN COMPANIES, INC.
		(Registrant)

		By: /s/ W. MATT RALLS
		W. Matt Ralls
		President and Chief Executive officer

		Date: March 1, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.

Signature		Title	Date

/s/ W. MATT RALLS		President, Chief Executive Officer and Director	March 1, 2011
(W. Matt Ralls)

/s/ W. H. WELLS		Principal Financial Officer	March 1, 2011
(W. H. Wells)

/s/ GREGORY M. HATFIELD		Principal Accounting Officer	March 1, 2011
(Gregory M. Hatfield)

*		Director	March 1, 2011
(R. G. Croyle)

*		Director	March 1, 2011
(William T. Fox III)

*		Director	March 1, 2011
(Sir Graham Hearne)

*		Director	March 1, 2011
(Thomas R. Hix)

*		Director	March 1, 2011
(Robert E. Kramek)

*		Director	March 1, 2011
(Frederick R. Lausen)

*		Chairman of the Board	March 1, 2011
(H. E. Lentz)

*		Director	March 1, 2011
(Lord Moynihan)

*		Director	March 1, 2011
(Suzanne P. Nimocks)

*		Director	March 1, 2011
(P. Dexter Peacock)

*		Director	March 1, 2011
(John J. Quicke)

*By:	/s/ W. MATT RALLS
	(W. Matt Ralls, Attorney-in-Fact)

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