UNITED STATES

 SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________

Form 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

Commission file number: 1-13289

_______________

Pride International, Inc.

(Exact name of registrant as specified in its charter)

Delaware	76-0069030
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5847 San Felipe, Suite 3300	77057
Houston, Texas	(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code:

(713) 789-1400

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

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, $.01 par value	New York Stock Exchange
Rights to Purchase Preferred Stock	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.  Yes þ     No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of the Act.  Yes  ¨    No þ

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 þ     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 þ 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.  þ

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

                                       (Do not check if a smaller reporting company)

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

The aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2009, based on the closing price on the New York Stock Exchange on such date, was approximately $4.3 billion. (The current executive officers and directors of the registrant are considered affiliates for the purposes of this calculation.)

The number of shares of the registrant’s common stock outstanding on February 15, 2010 was 175,576,393.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the Annual Meeting of Stockholders to be held in May 2010 are incorporated by reference into Part III of this annual report.

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TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	3
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	22
Item 3.	Legal Proceedings	22
Item 4.	Submission of Matters to a Vote of Security Holders	23
	Executive Officers of the Registrant	23
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 8.	Financial Statements and Supplementary Data	52
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
Item 9A.	Controls and Procedures	86
Item 9B.	Other Information	86
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	87
Item 11.	Executive Compensation	87
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	87
Item 13.	Certain Relationships and Related Transactions, and Director Independence	87
Item 14.	Principal Accounting Fees and Services	87
PART IV
Item 15.	Exhibits, Financial Statement Schedules	88

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PART I

ITEM 1.  BUSINESS

In this Annual Report on Form 10-K, “we,” the “Company” and “Pride” are references to Pride International, Inc. and its subsidiaries, unless the context clearly indicates otherwise. Pride International, Inc. is a Delaware corporation with its principal executive offices located at 5847 San Felipe, Suite 3300, Houston, Texas 77057. Our telephone number at such address is (713) 789-1400 or (800) 645-2067.

We are one of the world’s largest offshore drilling contractors operating, as of February 19, 2010, a fleet of 23 rigs, consisting of two deepwater drillships, 12 semisubmersible rigs, seven jackups and two managed deepwater drilling rigs. We also have four deepwater drillships under construction. Our customers include major integrated oil and natural gas companies, state-owned national oil companies and independent oil and natural gas companies. Our competitors range from large international companies offering a wide range of drilling services to smaller companies focused on more specific geographic or technological areas.

We are continuing to increase our emphasis on deepwater drilling. Although crude oil prices have declined from the record levels reached in mid-2008, we believe the long-term prospects for deepwater drilling are positive given that the expected growth in oil consumption from developing nations, limited growth in crude oil supplies and high depletion rates of mature oil fields, together with geologic successes, improving access to promising offshore areas and new, more efficient technologies, will continue to be catalysts for the long-term exploration and development of deepwater fields. Since 2005, we have invested or committed to invest over $3.7 billion in the expansion of our deepwater fleet, including four new ultra-deepwater drillships under construction. Three of the drillships have multi-year contracts at favorable rates, with two scheduled to work in the strategically important deepwater U.S. Gulf of Mexico, which, in addition to our operations in Brazil and West Africa, provides us with exposure to all three of the world’s most active deepwater basins. Since 2005, we also have disposed of non-core assets, generating $1.6 billion in proceeds, enabling us to increasingly focus our financial and human capital on deepwater drilling.  In addition, on August 24, 2009, we completed the spin-off of Seahawk Drilling, Inc., which holds the assets and liabilities that were associated with our mat-supported jackup rig business.

Our customers reduced exploration and development spending in 2009, especially in midwater and shallow water drilling programs, due to the economic downturn and decline in crude oil prices.  We anticipate that deepwater activity will outperform other drilling sectors due in part to an early stage of exploration and production in most deepwater basins around the world, which has led to strong geologic success and should further lead to increased long-term client demand, as numerous field development programs are initiated, providing greater insulation from short-term commodity price fluctuations. Also, the average reserve estimates for many deepwater discoveries to date far exceed that of the shallow and midwater sectors, resulting in more favorable drilling economics.  An increasing focus on deepwater prospects by national oil companies, whose activities tend to be less sensitive to general economic factors, serve to provide further stability in the deepwater sector.  Our contract backlog at December 31, 2009 totals $6.9 billion and is comprised primarily of contracts for deepwater rigs with large integrated oil and national oil companies possessing long-term development plans.  

We provide contract drilling services to oil and natural gas exploration and production companies through the use of mobile offshore drilling rigs in U.S. and international waters. We provide the rigs and drilling crews and are responsible for the payment of operating and maintenance expenses. In addition, we also provide rig management services on a variety of rigs, consisting of technical drilling assistance, personnel, repair and maintenance services and drilling operation management services.

Segment Information

We organize our reportable segments based on the water depth operating capabilities of our drilling rigs. Our reportable segments include Deepwater, which consists of our rigs capable of drilling in water depths of 4,500 feet and greater; Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less; and Independent Leg Jackups, which consists of our rigs capable of operating in water depths up to 300 feet. We also manage the drilling operations for deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations.

We incorporate by reference in response to this item the segment information for the last three years set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Segment Review” in Item 7 of this annual report and Note 14 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report. We also incorporate by reference in response to this item the information with respect to backlog and acquisitions and dispositions of assets set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments”, “— Our Business”, “— Backlog” and “— Liquidity and Capital Resources” in Item 7 and in Notes 2 and 3 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report.

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Rig Fleet

The table below presents information about our rig fleet as of February 19, 2010:

			Water Depth Rating     (In Feet)	Drilling Depth Rating     (In Feet)
Rig Name	Rig Type / Design	Built / Upgraded			Location	Status
Deepwater
Drillships Under Construction — 4
Deep Ocean Ascension	Samsung, DP3	Exp Q1 2010	12,000	40,000	S. Korea	Shipyard
Deep Ocean Clarion	Samsung, DP3	Exp Q3 2010	12,000	40,000	S. Korea	Shipyard
Deep Ocean Mendocino	Samsung, DP3	Exp Q1 2011	12,000	40,000	S. Korea	Shipyard
Deep Ocean Molokai	Samsung, DP3	Exp Q4 2011	12,000	40,000	S. Korea	Shipyard
Drillships — 2
Pride Africa	Gusto 10,000, DP	1999	10,000	30,000	Angola	Working
Pride Angola	Gusto 10,000, DP	1999	10,000	30,000	Angola	Working
Semisubmersibles — 6
Pride North America	Bingo 8000	1999	7,500	25,000	Egypt	Working
Pride South Pacific	Sonat Offshore /Aker	1974/1999/ 2009	6,500	25,000	Equitorial Guinea	Working
Pride Portland	Amethyst 2 Class, DP	2004	5,700	25,000	Brazil	Working
Pride Rio de Janeiro	Amethyst 2 Class, DP	2004	5,700	25,000	Brazil	Working
Pride Brazil	Amethyst 2 Class, DP	2001/2009	5,600	25,000	Brazil	Working
Pride Carlos Walter	Amethyst 2 Class, DP	2000	5,000	25,000	Brazil	Working
Midwater — 6
Pride South America(1)	Amethyst, DP	1987/1996	4,000	12,000	Brazil	Working
Pride Mexico	Neptune Pentagon	1973/1995/2008	2,650	25,000	Brazil	Working
Pride South Atlantic	F&G Enhanced Pacesetter	1982	1,500	25,000	Brazil	Working
Pride Venezuela	F&G Enhanced Pacesetter	1982/2001	1,500	25,000	Dubai	Shipyard
Sea Explorer	Aker H-3	1975/2001	1,000	25,000	Brazil	Working
Pride South Seas	Aker H-3	1977/1997	1,000	20,000	South Africa	Idle
Independent Leg Jackup Rigs - 7
Pride Cabinda	Independent leg, cantilever	1983	300	25,000	Gabon	Shipyard
Pride Hawaii	Independent leg, cantilever	1975/1997	300	21,000	India	Working
Pride Pennsylvania	Independent leg, cantilever	1973/1998	300	20,000	Dubai	Shipyard
Pride Tennessee	Independent leg, cantilever	1981/2007	300	20,000	USA	Idle
Pride Wisconsin	Independent leg, slot	1976/2002	300	20,000	USA	Stacked
Pride Montana	Independent leg, cantilever	1980/2001	270	20,000	Mid-East	Working
Pride North Dakota	Independent leg, cantilever	1981/2002	250	30,000	Mid-East	Working
Managed Rigs — 2
Thunder Horse	Moored Semisubmersible Drilling Rig	2004	6000	25,000	USA	Working
Kizomba B	Tension Leg Platform Rig	2004	5000	20,000	Angola	Working

(1) Outfitted for workover activity

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Drillships.  Our drillships, including the four under construction,are deepwater, self-propelled drillships that can be positioned over a drill site through the use of a computer-controlled thruster (dynamic positioning) system. Drillships are suitable for deepwater drilling in remote locations because of their mobility and large load-carrying capacity. Generally, these drillships operate with crews of approximately 100 persons.

Semisubmersible Rigs.  Our semisubmersible rigs, six of which are in our deepwater fleet and six of which are in our midwater fleet, are floating platforms. They can be submerged to a predetermined depth, by means of a water ballasting system, so that a substantial portion of the lower hulls, or pontoons, is below the water surface during drilling operations. The rig is “semisubmerged,” remaining afloat in a position, off the sea bottom, where the lower hull is about 60 to 80 feet below the water line and the upper deck protrudes well above the surface. This type of rig maintains its position over the well through the use of either an anchoring system or a computer-controlled thruster system similar to that used by our drillships. Semisubmersible rigs generally operate with crews of 60 to 75 persons.

Independent Leg Jackup Rigs.  The jackup rigs we operate are mobile, self-elevating drilling platforms equipped with legs that penetrate the ocean floor until a solid foundation is reached to support the drilling platform. Our jackup rigs are generally limited to operating in water depths of up to 300 feet. The length of the rig’s legs, sea bed condition, expected weather conditions, the presence of a platform and the positioning of the rig over the platform determine the water depth limit and suitability of a particular rig for a project. A cantilever jackup rig has a feature that allows the drilling platform to be extended out from the hull, enabling the rig to perform drilling or workover operations over a pre-existing platform or structure. Slot-type jackup rigs are configured for drilling operations to take place through a slot in the hull. Slot-type rigs are usually used for exploratory drilling because their configuration makes them difficult to position over existing platforms or structures. Jackups generally operate with crews of 40 to 60 persons.

Managed Deepwater Rigs.  We perform rig management services for drilling operations for two deepwater rigs owned by others, located offshore Angola and in the U.S. Gulf of Mexico. Our services consist of providing technical assistance, personnel, repair and maintenance services and drilling operation management services. The drilling equipment, which we operate on behalf of our customers, is installed on tension-leg platform and semisubmersible hull designs. Due to the similar drilling equipment specifications and operations among our managed deepwater rigs and our owned deepwater rigs, our managed rig personnel and the rig crews on our owned rigs require similar experience and training.

Customers

We provide contract drilling and related services to a customer base that includes large multinational oil and natural gas companies, government-owned oil and natural gas companies and independent oil and natural gas producers. For the year ended December 31, 2009, Petroleo Brasilerio S.A. and Total S.A. accounted for 33% and 16%, respectively, of our consolidated revenues from continuing operations. The loss of any of these significant customers could have a material adverse effect on our results of operations.

Drilling Contracts

Overview

Our drilling contracts are awarded through competitive bidding or on a negotiated basis. The contract terms and rates vary depending on competitive conditions, geographical area, geological formation to be drilled, equipment and services to be supplied, on-site drilling conditions and anticipated duration of the work to be performed.

Oil and natural gas well drilling contracts are carried out on a dayrate, footage or turnkey basis. Currently, all of our offshore drilling services contracts are on a dayrate basis. Under dayrate contracts, we charge the customer a fixed amount per day regardless of the number of days needed to drill the well. In addition, dayrate contracts usually provide for a reduced dayrate (or lump-sum amount) for mobilizing the rig to the well location or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. Our dayrate contracts also generally include cost adjustment provisions that allow changes to our dayrate in order to keep our operating margin unchanged in times of increasing or decreasing operating costs. A dayrate drilling contract generally covers either the drilling of a single well or group of wells or has a stated term. In some instances, the dayrate contract term may be extended by the customer exercising options for the drilling of additional wells or for an additional length of time at fixed or mutually agreed terms, including dayrates.

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       Another type of contract provides for payment on a footage basis, whereby a fixed amount is paid for each foot drilled regardless of the time required or the problems encountered in drilling the well. We may also enter into turnkey contracts, whereby we agree to drill a well to a specific depth for a fixed price and to bear some of the well equipment costs. Compared with dayrate contracts, footage and turnkey contracts involve a higher degree of risk to us.

Our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime or operational problems above a contractual limit or safety-related issues, if the rig is a total loss, if the rig is not delivered to the customer, or in certain circumstances does not pass acceptance testing, within the period specified in the contract or in other specified circumstances. In addition, a number of our long-term drilling contracts are cancelable by the customer for convenience upon the payment of a termination fee.  The termination fees vary from contract to contract and range from (1) the remaining revenue under the contract to (2) the present value of the cash margin for the remaining term to (3) a reduced dayrate for the remaining term.  For some contracts, the termination fee includes the payment of mobilization and demobilization fees and may be reduced to the extent of the dayrate obtained for the rig on another contract. For jackup rigs, certain customers may require contracts that are cancelable, without cause, upon little or no prior notice and without penalty or early termination payments. A customer is more likely to seek to cancel or renegotiate its contract during periods of depressed market conditions. We could be required to pay penalties if some of our contracts with our customers are canceled due to downtime, operational problems or failure to deliver. Suspension of drilling contracts results in the reduction in or loss of dayrate for the period of the suspension. If our customers cancel some of our significant contracts and we are unable to secure new contracts on substantially similar terms, or at all, or if contracts are suspended for an extended period of time, it could adversely affect our consolidated financial statements.

Deepwater

The Pride Africa is currently operating under a contract expiring in December 2011. In 2008, the Pride Angola obtained a five-year contract expiring in July 2013. In February 2008, the Pride Portland and the Pride Rio de Janeiro were awarded contract extensions into 2016 and 2017, respectively, in direct continuation of their current contracts. The Pride South Pacific completed a two-year contract in March 2009 and was awarded a one-year contract in 2009 commencing in January 2010. In November 2006, we were awarded five-year contract extensions that began in mid-2008 for the Pride Brazil and the Pride Carlos Walter and a three-year contract extension that began in early 2008 for the Pride North America. For information about the contract status of our four drillships under construction, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments — Investments in Deepwater Fleet” in Item 7 of this annual report.

Midwater

The Pride South America is operating under a five-year contract expiring in February 2012. The Pride Mexico commenced a five-year contract in July 2008. The Pride South Atlantic commenced its new five-year contract in April 2008. The Sea Explorer commenced a two-year contract in November 2009. During the second quarter of 2009, we and the customer mutually agreed to terminate the Pride Venezuela’s then-existing contract, thereby releasing the rig for mobilization to a shipyard in Dubai for further evaluation and completion of a rig refurbishment project, which is expected to be completed in the second quarter of 2010.  The Pride Venezuela is being marketed for work in mid-2010 in several international areas. During the third quarter of 2009, the Pride South Seas concluded an eight well contract that had commenced in March 2008, and is currently in the process of being cold stacked with limited prospects for further work in the near to intermediate term.

Independent Leg Jackups

During the third quarter of 2009, our two independent jackup rigs in the Gulf of Mexico, the Pride Wisconsin and Pride Tennessee, completed contracts, with no immediate prospects for work. The Pride Wisconsin is currently cold stacked and the Pride Tennessee is idle.  Of our five independent leg jackup rigs operating outside the Gulf of Mexico, the Pride Hawaii is under contractto March 2010, the Pride Montana to June 2011 and the Pride North Dakota, inclusive of an unexercised priced option,to May 2010.  The Pride Cabinda completed a one-year contract in August 2009, a two-month contract in October 2009 and a two-month contract in February 2010 and is currently in the shipyard completing leg repairs before commencing its next contract. The Pride Pennsylvania completed a three-year contract in October 2009 and is currently in the shipyard with no future contracted work.

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Other Operations

Other operations include our deepwater drilling operations management contracts and other operating activities.  Management contracts in 2009 included one management contract that ended in the third quarter of 2009 and two contracts that expire in March 2010 and 2012 (with early termination permitted in certain cases).  Management contracts in 2008 included two additional contracts that ended in the third and fourth quarters of 2008.  Additionally, the operations of our former shallow-water platform rig fleet, which were historically included in other operations, were part of Seahawk’s business that was distributed to our shareholders in August 2009.

Competition

The contract drilling industry is highly competitive.  Demand for contract drilling and related services is driven primarily by expectations about future prices of oil and natural gas.  Future oil and natural gas prices are primarily impacted by both actual and expected global energy demand and its growth, geologic success rates, worldwide productive capacity and depletion rates.  In addition to these more customary supply/demand drivers, the price of oil can also be influenced by concerns over potential supply disruptions caused by geopolitical conflicts, the strategic direction of the Organization of Petroleum Exporting Countries (“OPEC”), and its ability to maintain stated production levels and the policies and restrictions of various governments concerning access to and the exploration and development of their oil and natural gas reserves.  Demand for shallow and many mid-water drilling services, particularly in mature basins with small reservoirs and steep decline rates, tend to be more sensitive to near term oil price expectations, while deepwater and some mid-water projects tend to be less sensitive to near term commodity price changes because of reservoir size and the longer lead times required for planning and development.

Drilling contracts are generally awarded on a competitive bid basis. Pricing, safety record and competency are key factors in determining which qualified contractor is awarded a job.  Rig availability, location and technical ability also can be significant factors in the determination. Operators also may consider crew experience and efficiency. Some of our contracts are on a negotiated basis. We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future. Certain competitors may have greater financial resources than we do, which may better enable them to withstand periods of low utilization, compete more effectively on the basis of price, build new rigs or acquire existing rigs.

Our competition ranges from large international companies to smaller, locally owned companies. We believe we are competitive in terms of safety, pricing, performance, equipment, availability of equipment to meet customer needs and availability of experienced, skilled personnel; however, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business can occur. Competition for offshore rigs is usually on a global basis, as these rigs are highly mobile and may be moved, at a cost that is sometimes substantial, from one region to another in response to demand.

Seasonality

When operating in the Gulf of Mexico, rigs are subject to severe weather during certain periods of the year, particularly during hurricane season from June through November, which could halt the operations of certain of these rigs for prolonged periods or limit contract opportunities during that period. Otherwise, our business activities are not significantly affected by seasonal fluctuations.

Insurance

Our operations are subject to hazards inherent in the drilling of oil and natural gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, or seriously damage or destroy the equipment involved. Offshore drilling operations are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Our marine package policy provides insurance coverage for physical damage to our rigs, liability due to control-of-well events and loss of hire insurance for certain assets with higher dayrates. This insurance policy has a $10 million aggregate deductible and $10 million per occurrence deductible.  We currently do not carry windstorm coverage. We are evaluating the level of coverage that we will obtain once the Deep Ocean Ascension is operating in the Gulf of Mexico. We also maintain insurance coverage for cargo, automobile liability, non-owned aviation, personal injury and similar liabilities. Those policies have significantly lower deductibles, generally less than $1 million.

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Environmental and Other Regulatory Matters

Our operations include activities that are subject to numerous international, federal, state and local laws and regulations, including the U.S. Oil Pollution Act of 1990, the U.S. Outer Continental Shelf Lands Act, the Comprehensive Environmental Response, Compensation and Liability Act and the International Convention for the Prevention of Pollution from Ships, governing the discharge of materials into the environment or otherwise relating to environmental protection. In certain circumstances, these laws may impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. Numerous governmental agencies issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance or limit contract drilling opportunities could adversely affect our consolidated financial statements. While we believe that we are in substantial compliance with the current laws and regulations, there is no assurance that compliance can be maintained in the future. We do not presently anticipate that compliance with currently applicable environmental laws and regulations will have a material adverse effect on our consolidated financial statements.

The Minerals Management Service of the U.S. Department of the Interior (“MMS”) has issued guidelines for jackup rig fitness requirements in the U.S. Gulf of Mexico for future hurricane seasons through 2013 and may take other steps that could increase the cost of operations or reduce the area of operations for our jackup rigs, thus reducing their marketability. Implementation of new MMS guidelines or regulations may subject us to increased costs or limit the operational capabilities of our rigs and could materially and adversely affect our operations and financial condition. Please read “Risk Factors — Our ability to operate our rigs in the U.S. Gulf of Mexico could be restricted or made more costly by government regulation” in Item 1A of this annual report.

The United States Clean Water Act prohibits the discharge of oil or hazardous substances in U.S. navigable waters and imposes strict liability in the form of penalties for unauthorized discharges.  Pursuant to regulations promulgated by the U.S. Environmental Protection Agency (“EPA”) in the early 1970s, the discharge of sewage from vessels and effluent from properly functioning marine engines was exempted from the permit requirements of the National Pollution Discharge Elimination System.  This exemption allowed vessels in U.S. waters to discharge certain substances incidental to the normal operation of a vessel, including ballast water, without obtaining a permit to do so.  In September 2006, in response to a challenge by certain environmental groups and the United States, a U.S. District Court issued an order invalidating the exemption.  As a result of this ruling, as of December 19, 2008, the EPA requires a permit for such discharges.  The EPA issued a general permit available to vessel owners to cover the discharges, which includes effluent limits, specific corrective actions, inspections and monitoring, recordkeeping and reporting requirements.  As a result, like others in our industry, we are subject to this new permit requirement, but do not presently anticipate that compliance with this requirement will have a material adverse effect on our operations.

Our international operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of drilling rigs and equipment, currency conversions and repatriation, oil and natural gas exploration and development, environmental protection, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drilling rigs and other equipment. New environmental or safety laws and regulations could be enacted, which could adversely affect our ability to operate in certain jurisdictions. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.

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Employees

As of December 31, 2009, we employed approximately 3,550 personnel and had approximately 470 contract personnel working for us. Approximately 660 of our employees and contractors were located in the United States and 3,360 were located outside the United States. Rig crews constitute the majority of our employees. None of our U.S. employees are represented by a collective bargaining agreement. Many of our international employees are subject to industry-wide labor contracts within their respective countries.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments to these filings, are available free of charge through our internet website at www.prideinternational.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the Securities and Exchange Commission. These reports also are available at the SEC’s internet website at www.sec.gov. Information contained on or accessible from our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.

ITEM 1A.  RISK FACTORS

Risk Factors About Our Business

A material or extended decline in expenditures by oil and natural gas companies due to a decline or volatility in crude oil and natural gas prices, a decrease in demand for crude oil and natural gas or other factors may reduce demand for our services and substantially reduce our profitability or result in our incurring losses.

The profitability of our operations depends upon conditions in the oil and natural gas industry and, specifically, the level of exploration, development and production activity by oil and natural gas companies.  Crude oil and natural gas prices and market expectations regarding potential changes in these prices significantly affect this level of activity.  However, higher commodity prices do not necessarily translate into increased drilling activity because our customers’ expectations of future commodity prices typically drive demand for our rigs.  Crude oil and natural gas prices are volatile.  Commodity prices are directly influenced by many factors beyond our control, including:

• the demand for crude oil and natural gas;

• the cost of exploring for, developing, producing and delivering crude oil and natural gas;

• expectations regarding future energy prices;

• advances in exploration, development and production technology;

• government regulations;

• local and international political, economic and weather conditions;

• the ability of OPEC to set and maintain production levels and prices;

• the level of production in non-OPEC countries;

• domestic and foreign tax policies;

• the development and exploitation of alternative fuels;

• the policies of various governments regarding exploration and development of their oil and natural gas reserves;

• acts of terrorism in the United States or elsewhere; and

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• the worldwide military and political environment and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East and other oil and natural gas producing regions.

Over the past 18 months, corporate credit availability and capital market access has been volatile and uncertain, leading to periods of liquidity shortages for industrial businesses worldwide.  While recent economic trends have stabilized, and public debt markets were active in the second half of 2009, bank credit availability remains weak.  In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks against the United States or other countries could further the downturn in the economies of the United States and those of other countries.  A slowdown in economic activity would likely reduce worldwide demand for energy and result in an extended period of lower crude oil and natural gas prices.  Any prolonged reduction in crude oil and natural gas prices will depress the levels of exploration, development and production activity.  Moreover, even during periods of high commodity prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their lack of success in exploration efforts.  These factors could cause our revenues and margins to decline, decrease daily rates and utilization of our rigs and limit our future growth prospects. Any significant decrease in daily rates or utilization of our rigs, particularly our high-specification drillships or semisubmersible rigs, could materially reduce our revenues and profitability. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain insurance coverages that we consider adequate or are otherwise required by our contracts.

Our customers may seek to cancel or renegotiate some of our drilling contracts during periods of depressed market conditions or if we experience downtime, operational difficulties, or safety-related issues.

Currently, our contracts with customers are dayrate contracts, where we charge a fixed charge per day regardless of the number of days needed to drill the well.  During depressed market conditions, a customer may no longer need a rig that is currently under contract or may be able to obtain a comparable rig at a lower daily rate.  As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts.  In addition, our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime or operational problems above the contractual limit or safety-related issues, if the rig is a total loss, if the rig is not delivered to the customer or, in certain circumstances, does not pass acceptance testing within the period specified in the contract or in other specified circumstances, which include events beyond the control of either party.  Some of our contracts with our customers include terms allowing them to terminate contracts without cause, with little or no prior notice and with minimal penalty or early termination payments.  In addition, we could be required to pay penalties, which could be material, if some of our contracts with our customers are terminated due to downtime, operational problems or failure to deliver.  Some of our other contracts with customers may be cancelable at the option of the customer upon payment of a termination fee, which may not fully compensate us for the loss of the contract. In addition, a customer that is the subject of a bankruptcy filing may elect to reject its drilling contract.  Early termination of a contract may result in a rig being idle for an extended period of time.  The likelihood that a customer may seek to terminate a contract is increased during periods of market weakness.  If our customers cancel some of our significant contracts and we are unable to secure new contracts on substantially similar terms, or at all, our revenues and profitability could be materially reduced.

Rig upgrade, refurbishment, repair and construction projects are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.

We have expended, and will continue to expend, significant amounts of capital to complete the construction of our four drillships currently under construction.  Depending on available opportunities, we may construct additional rigs for our fleet in the future.  In addition, we make significant upgrade, refurbishment and repair expenditures for our fleet from time to time, particularly in light of the age of some of our rigs.   Some of these expenditures are unplanned.  In 2010, we expect to spend approximately $680 million with respect to the continued construction of our four drillships and an additional approximately $200 million with respect to the refurbishment and upgrade of other rigs.

All of these projects are subject to the risks of delay or cost overruns, including costs or delays resulting from the following:

• unexpectedly long delivery times for or shortages of key equipment, parts and materials;

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• shortages of skilled labor and other shipyard personnel necessary to perform the work;

• failure or delay of third-party equipment vendors or service providers;

• unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;

• unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment;

• unanticipated change orders;

• client acceptance delays;

• disputes with shipyards and suppliers;

• work stoppages and other labor disputes;

• latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;

• financial or other difficulties at shipyards and suppliers;

• acts of war;

• adverse weather conditions; and

• inability to obtain required permits or approvals.

Significant cost overruns or delays could materially affect our financial condition and results of operations.  Some of our risks are concentrated because our four drillships currently under construction are located at one shipyard in South Korea.  Delays in the delivery of rigs being constructed or undergoing upgrade, refurbishment or repair may, in many cases, result in delay in contract commencement, resulting in a loss of revenue to us, and may also cause our customer to renegotiate the drilling contract for the rig or terminate or shorten the term of the contract under applicable late delivery clauses.  In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms, if at all.  Additionally, capital expenditures for rig upgrade, refurbishment and construction projects could materially exceed our planned capital expenditures.  Moreover, our rigs undergoing upgrade, refurbishment and repair may not earn a dayrate during the period they are out of service.

An oversupply of comparable or higher specification rigs in the markets in which we compete could depress the demand and contract prices for our rigs and materially reduce our revenues and profitability.

Contract prices customers pay for our rigs also are affected by the total supply of comparable rigs available for service in the markets in which we compete.  During prior periods of high utilization and dayrates, industry participants have increased the supply of rigs by ordering the construction of new units.  This has often created an oversupply of drilling units and has caused a decline in utilization and dayrates when the rigs enter the market, sometimes for extended periods of time as these rigs are absorbed into the active fleet.  Since 2007, 60 jackup rigs have been added to the global fleet, with another 53 expected to be added in 2010 and 2011.  Most of these units are cantilevered units and are considered to be of a higher specification than other types of jackup rigs, because they generally are larger, have greater deckloads and have water depth ratings of 300 feet or greater. In the deepwater sector, 11 drillships and 19 new semi-submersible rigs entered the market from 2007 through 2009, and there have been announcements of approximately 70 new semisubmersible rigs and drillships with delivery forecasted to occur from 2010 through 2012, including our four drillship construction projects. A number of the contracts for units currently under construction provide for options for the construction of additional units, and further new construction announcements may occur for all classes of rigs pursuant to the exercise of one or more of these options and otherwise.  Not all of the rigs currently under construction have been contracted for future work, which may intensify price competition as scheduled delivery dates occur.  In addition, our and our competitors’ rigs that are “stacked” (i.e., minimally crewed with little or no scheduled maintenance being performed) may re-enter the market.  The entry into service of newly constructed, upgraded or reactivated units will increase marketed supply and could reduce, or curtail a strengthening of, dayrates in the affected markets as rigs are absorbed into the active fleet. Any further increase in construction of new drilling units may negatively affect utilization and dayrates. In addition, projects increasingly are using enhanced development technologies, resulting in the construction of more complex well bores. This could require us to make material additional capital investments to our fleet in order to stay competitive and address changing customer needs.

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Our industry is highly competitive and cyclical, with intense price competition.

Our industry is highly competitive.  Our contracts are traditionally awarded on a competitive bid basis.  Pricing, rig availability, safety record and competency are key factors in determining which qualified contractor is awarded a job.  Location and technical ability also can be significant factors in the determination.  Some of our competitors in the drilling industry are larger than we are and have more diverse fleets, or fleets with generally higher specifications, and greater resources than we have.  Some of these competitors also are incorporated in tax-haven countries outside the United States, which provides them with significant tax advantages that are not available to us as a U.S. company and which may materially impair our ability to compete with them for many projects that would be beneficial to our company.  In addition, recent consolidations within the oil and natural gas industry have reduced the number of available customers, resulting in increased competition for projects.  We may not be able to maintain our competitive position, and we believe that competition for contracts will continue to be intense in the foreseeable future.  Our inability to compete successfully may reduce our revenues and profitability.

Historically, the offshore service industry has been highly cyclical, with periods of high demand, limited rig supply and high dayrates often followed by periods of low demand, excess rig supply and low dayrates.  Periods of low demand and excess rig supply intensify the competition in the industry and often result in rigs, particularly rigs like our lower specification semisubmersible rigs and jackups, being idle for long periods of time.  We may be required to stack rigs or enter into lower dayrate contracts in response to market conditions.  Prolonged periods of low utilization and dayrates could result in the recognition of impairment charges on certain of our rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

Consolidation of suppliers may limit our ability to obtain supplies and services at an acceptable cost, on our schedule or at all.

Our operations rely on a significant supply of capital and consumable spare parts and equipment to maintain and repair our fleet.  We also rely on the supply of ancillary services, including supply boats and helicopters. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing of key supplies and services.  We may not be able to obtain supplies and services at an acceptable cost, at the times we need them or at all.  These cost increases, delays or unavailability could negatively impact our future operations and result in increases in rig downtime, and delays in the repair and maintenance of our fleet.

Failure to attract and retain skilled personnel or an increase in labor costs could hurt our operations.

We require highly skilled personnel to operate and provide technical services and support for our business.  Competition for the skilled and other labor required for our operations intensifies as the number of rigs activated or added to worldwide fleets or under construction increases, creating upward pressure on wages.  In periods of high utilization, we have found it more difficult to find and retain qualified individuals. We have experienced tightening in the relevant labor markets since 2005 and have recently sustained the loss of experienced personnel to our customers and competitors. Our labor costs have increased significantly since 2005 and, while we expect this trend to moderate in 2010, shortages of certain skilled positions and in certain geographic locations continue.The shortages of qualified personnel or the inability to obtain and retain qualified personnel could negatively affect the quality, safety and timeliness of our work.  In addition, our ability to crew our four new drillships and to expand our deepwater operations depends in part upon our ability to increase the size of our skilled labor force.  We have intensified our recruitment and training programs in an effort to meet our anticipated personnel needs.  These efforts may be unsuccessful, and competition for skilled personnel could materially impact our business by limiting or affecting the quality and safety of our operations or further increasing our costs.

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Our international operations involve additional risks not generally associated with domestic operations, which may hurt our operations materially.

In 2009, we derived 97% of our revenues from countries outside the United States.  Our operations in these areas are subject to the following risks, among others:

• political, social and economic instability, war and civil disturbances;

• seizure, expropriation or nationalization of assets or confiscatory taxation;

• significant governmental influence over many aspects of local economies;

• unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws;

• restrictions on currency or capital repatriation;

• work stoppages;

• foreign currency fluctuations and devaluations;

• damage to our equipment or violence directed at our employees, including kidnappings;

• complications associated with repairing and replacing equipment in remote locations;

• repudiation, nullification, modification or renegotiation of contracts;

• limitations on insurance coverage, such as war risk coverage, in certain areas;

• piracy;

• solicitation by governmental officials for improper payments or other forms of corruption;

• imposition of trade barriers;

• wage and price controls;

• import-export quotas;

• uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate;

• acts of terrorism; and

• other forms of government regulation and economic conditions that are beyond our control.

We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where we do not take protective measures against exposure to a foreign currency.  We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.  We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts providing for payment in U.S. dollars or freely convertible foreign currency.  To the extent possible, we seek to limit our exposure to local currencies by matching the acceptance of local currencies to our expense requirements in those currencies.  Although we have done this in the past, we may not be able to take these actions in the future, thereby exposing us to foreign currency fluctuations that could cause our results of operations, financial condition and cash flows to deteriorate materially.

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     Our ability to compete in international contract drilling markets may be limited by foreign governmental regulations that favor or require the awarding of contracts to local contractors or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction.  Furthermore, our foreign subsidiaries may face governmentally imposed restrictions from time to time on their ability to transfer funds to us.  Finally, governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries.  In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so.  Operations in less developed countries can be subject to legal systems which are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations.  Our import activities are governed by unique customs laws and regulations in each of the countries where we operate.  Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations.  Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.

The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing.  These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations.  Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes.  Shipping delays or denials could cause unscheduled operational downtime.  Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.

Although we implement and enforce policies and procedures designed to promote compliance with the laws of the jurisdictions in which we operate, our employees, contractors and agents may take actions in violation of our policies and such laws.  Any such violation, even if prohibited by our policies, could materially and adversely affect our business.

We are conducting an investigation into allegations of improper payments to foreign government officials, as well as corresponding accounting entries and internal control issues.  The outcome and impact of this investigation are unknown at this time.

During the course of an internal audit and investigation relating to certain of our Latin American operations, our management and internal audit department received allegations of improper payments to foreign government officials. In February 2006, the Audit Committee of our Board of Directors assumed direct responsibility over the investigation and retained independent outside counsel to investigate the allegations, as well as corresponding accounting entries and internal control issues, and to advise the Audit Committee.

The investigation has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.

The Audit Committee, through independent outside counsel, has undertaken a review of our compliance with the FCPA in certain of our other international operations.  This review has found evidence suggesting that during the period from 2001 through 2006 payments were made directly or indirectly to government officials in Saudi Arabia, Kazakhstan, Brazil, Nigeria, Libya, Angola and the Republic of the Congo in connection with clearing rigs or equipment through customs or resolving outstanding issues with customs, immigration, tax, licensing or merchant marine authorities in those countries. In addition, this review has found evidence suggesting that in 2003 payments were made to one or more third parties with the intent that they would be transferred to a government official in India for the purpose of resolving a customs dispute related to the importation of one of our jackup rigs. The evidence suggests that the aggregate amount of payments referred to in this paragraph is less than $2.5 million. In addition, the U.S. Department of Justice (“DOJ”) has asked us to provide information with respect to (a) our relationships with a freight and customs agent and (b) our importation of rigs into Nigeria.

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The investigation of the matters described above and the Audit Committee’s compliance review are substantially complete. Our management and the Audit Committee of our Board of Directors believe it likely that then members of our senior operations management either were aware, or should have been aware, that improper payments to foreign government officials were made or proposed to be made. Our former Chief Operating Officer resigned as Chief Operating Officer effective on May 31, 2006 and has elected to retire from the company, although he will remain an employee, but not an officer, until the completion of the investigation and related matters to assist us with the investigation and to be available for consultation and to answer questions relating to our business.  His retirement benefits will be subject to the determination by our Audit Committee or our Board of Directors that it does not have cause (as defined in his retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.

We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the DOJ and the SEC, and we have cooperated and continue to cooperate with these authorities.  For any violations of the FCPA, we may be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 per violation and a company that knowingly commits a violation can be fined up to $25 million per violation. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.

We are engaged in discussions with the DOJ and the SEC regarding a potential negotiated resolution of these matters, which could be settled during 2010 and which, as described above, could involve a significant payment by us.  We believe that it is likely that any settlement will include both criminal and civil sanctions.  We have accrued $56.2 million in anticipation of a possible resolution with the DOJ and the SEC of potential liabilities under the FCPA. This accrual represents our best estimate of potential fines, penalties and disgorgement related to such resolution. For tax purposes, fines and penalties are not deductible. The monetary sanctions ultimately paid by us to resolve these issues, whether imposed on us or agreed to by settlement, may exceed the amount of the accrual.  There can be no assurance that our discussions with the DOJ and SEC will result in a final settlement of any or all of these issues or, if a settlement is reached, the timing of any such settlement or that the terms of any such settlement would not have a material adverse effect on us.

We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests.  We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our company.  For additional information regarding a stockholder demand letter with respect to these matters, please see the discussion under “Demand Letter” in Note 13 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report.  In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets.  While we have made an accrual in anticipation of a possible resolution with the DOJ and SEC as discussed above, no amounts have been accrued related to any potential fines, sanctions, claims or other penalties referenced in this paragraph, which could be material individually or in the aggregate.

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Although, as discussed above, we are currently in discussions with the DOJ and the SEC regarding a possible resolution of potential liability under the FCPA, we cannot currently predict what, if any, actions may be taken by the DOJ, the SEC, any other applicable government or other authorities or our customers or other third parties or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.

If we are unable to renew or obtain new and favorable contracts for rigs whose contracts are expiring or are terminated, our revenues and profitability could be materially reduced.

We have a number of contracts that will expire in 2010 and 2011.  Our ability to renew these contracts or obtain new contracts and the terms of any such contracts will depend on market conditions.  We may be unable to renew our expiring contracts or obtain new contracts for the rigs under contracts that have expired or been terminated, and the dayrates under any new contracts may be substantially below the existing dayrates, which could materially reduce our revenues and profitability.

Many of our contracts with our customers for our offshore rigs are long-term dayrate contracts.  Increases in our costs, which are unpredictable and fluctuate based on events outside our control, could adversely impact our profitability.

In periods of rising demand for offshore rigs, a drilling contractor generally would prefer to enter into well-to-well or other shorter term contracts that would allow the contractor to profit from increasing dayrates, while customers with reasonably definite drilling programs would typically prefer longer term contracts in order to maintain dayrates at a consistent level.  Conversely, in periods of decreasing demand for offshore rigs, a drilling contractor generally would prefer longer term contracts to preserve dayrates and utilization, while customers generally would prefer well-to-well or other shorter term contracts that would allow the customer to benefit from the decreasing dayrates.  In 2009, a majority of our revenue was derived from long-term dayrate contracts, and substantially all of our backlog as of December 31, 2009 was attributable to long-term dayrate contracts. As a result, our inability to fully benefit from increasing dayrates in an improving market may limit our profitability.

In general, our costs increase as the business environment for drilling services improves and demand for oilfield equipment and skilled labor increases.  While many of our contracts include cost adjustment provisions that allow changes to our dayrate based on stipulated cost increases or decreases, the timing and amount earned from these dayrate adjustments may differ from our actual increase in costs.  Additionally, if our rigs incur idle time between contracts, we typically do not remove personnel from those rigs because we will use the crew to prepare the rig for its next contract.  During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed.  Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly.  In general, labor costs increase primarily due to higher salary levels and inflation.  Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment.  Contract preparation expenses vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are amortized.

Our current backlog of contract drilling revenue may not be ultimately realized.

As of December 31, 2009, our contract drilling backlog was approximately $6.9 billion for future revenues under firm commitments.  We may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our contracts for various reasons, including those described above.  Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

Our jackup rigs and some of our lower specification semisubmersible rigs are at a relative disadvantage to higher specification jackup and semisubmersible rigs.  These higher specification rigs may be more likely to obtain contracts than our lower specification rigs, particularly during market downturns.

Some of our competitors have jackup fleets with generally higher specification rigs than those in our jackup fleet, and our fleet includes a number of older and/or lower specification semisubmersible rigs.  In addition, the announced delivery between 2010 and 2012 of approximately 98 new rigs includes jackup rigs, semisubmersible rigs and deepwater drillships.  Particularly during market downturns when there is decreased rig demand, higher specification rigs may be more likely to obtain contracts than lower specification rigs. Some of our significant customers may also begin to require higher specification rigs for the types of projects that currently utilize our lower specification rigs, which could materially affect their utilization. Our lower specification rigs may be stacked earlier in the cycle as a result of decreased rig demand than many of our competitors’ higher specification rigs and may be reactivated later in the cycle, which could adversely impact our business. In addition, higher specification rigs may be more adaptable to different operating conditions and have greater flexibility to move to areas of demand in response to changes in market conditions. Furthermore, in recent years, an increasing amount of exploration and production expenditures have been concentrated in deeper water drilling programs and deeper formations, including deep natural gas prospects, requiring higher specification rigs. This trend is expected to continue and could result in a material decline in demand for the lower specification rigs in our fleet.

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We rely heavily on a small number of customers. The loss of a significant customer could have a material adverse impact on our financial results.

Our contract drilling business is subject to the usual risks associated with having a limited number of customers for our services.  For the year ended December 31, 2009, our two largest customers provided approximately 49% of our consolidated revenues.  Our results of operations could be materially adversely affected if any of our major customers terminates its contracts with us, fails to renew its existing contracts or refuses to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates.

Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2009, we had $1,192.0 million in debt.  This debt represented approximately 22% of our total capitalization.  Our current indebtedness may have several important effects on our future operations, including:

• a portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt and will not be available for other purposes;

• covenants contained in our debt arrangements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities; and

• our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes may be limited.

Our ability to meet our debt service obligations and to fund planned expenditures, including construction costs for our four drillship construction projects, will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control.  Our future cash flows may be insufficient to meet all of our debt obligations and contractual commitments, and any insufficiency could negatively impact our business.  To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings.

We are subject to a number of operating hazards, including those specific to marine operations.  We may not have insurance to cover all these hazards.

Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punchthroughs, craterings, fires, explosions and pollution.  Contract drilling and well servicing require the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties.  These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations.  Our offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations.  Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, personnel shortages or failure of subcontractors to perform or supply goods or services. We customarily provide contract indemnity to our customers for:

• claims that could be asserted by us relating to damage to or loss of our equipment, including rigs;

• claims that could be asserted by us or our employees relating to personal injury or loss of life; and

• legal and financial consequences of spills of industrial waste and other liquids, but generally only to the extent (1) that the waste or other liquids were in our control at the time of the spill, (2) that our level of culpability is greater than mere negligence or (3) of specified monetary limits.

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Certain areas in and near the Gulf of Mexico are subject to hurricanes and other extreme weather conditions on a relatively frequent basis.  When operating in the Gulf of Mexico, our drilling rigs may be located in areas that could cause them to be susceptible to damage or total loss by these storms.  In addition, damage caused by high winds and turbulent seas to our rigs, our shorebases and our corporate infrastructure could potentially cause us to curtail operations for significant periods of time until the damages can be repaired.

We maintain insurance for injuries to our employees, damage to or loss of our equipment and other insurance coverage for normal business risks, including general liability insurance.  Any insurance protection may not be sufficient or effective under all circumstances or against all hazards to which we may be subject.  For example, pollution, reservoir damage and environmental risks generally are not fully insurable.  Except for a portion of our deepwater fleet, we generally do not maintain business interruption or loss of hire insurance.  In addition, some of our primary insurance policies have substantial per occurrence or annual deductibles and/or self-insured aggregate amounts.

The oil and natural gas industry has sustained several catastrophic losses during the past few years, including damage from hurricanes in the Gulf of Mexico.  As a result, insurance underwriters have increased insurance premiums and restricted certain insurance coverage such as for losses arising from a named windstorm.  Our insurance policy has a $10 million aggregate deductible, and a $10 million per occurrence deductible.  Because of the high sub-limits for physical damage claims due to a named windstorm in the Gulf of Mexico and the reduction in our assets in the region following the spin-off of Seahawk, we currently do not carry windstorm coverage. We are evaluating the level of coverage that we will obtain once the Deep Ocean Ascension is operating in the Gulf of Mexico.

The occurrence of a significant event against which we are not fully insured, or of a number of lesser events against which we are insured but are subject to substantial deductibles, aggregate limits, and/or self-insured amounts, could materially increase our costs and impair our profitability and financial condition.  We may not be able to maintain adequate insurance at rates or on terms that we consider reasonable or acceptable or be able to obtain insurance against certain risks.

We may not be able to maintain or replace our rigs as they age.

The capital associated with the repair and maintenance of our fleet increases with age.  We may be required to make significant expenditures to maintain or repair rigs in our fleet, particularly some of our older semisubmersible rigs and jackups.  We may not be able to maintain our fleet of existing rigs to compete effectively in the market, and our financial resources may not be sufficient to enable us to make expenditures necessary for these purposes or to acquire or build replacement rigs.

We may incur substantial costs associated with workforce reductions.

In many of the countries in which we operate, our workforce has certain compensation and other rights arising from our various collective bargaining agreements and from statutory requirements of those countries relating to involuntary terminations.  If we choose to cease operations in one of those countries or if market conditions reduce the demand for our drilling services in such a country, we could incur costs, which may be material, associated with workforce reductions.

18

Failure to secure a drilling contract prior to deployment of the uncontracted drillship under construction or any other rigs we may construct in the future prior to their deployment could adversely affect our future results of operations.

Three of our four drillships under construction have long-term drilling contracts.  The drillship remaining to be contracted is scheduled for delivery in the fourth quarter of 2011.  We have not yet obtained a drilling contract for this drillship.  In addition, we may commence the construction of additional rigs for our fleet from time to time without first obtaining a drilling contract covering any such rig. Our failure to secure a drilling contract for any rig under construction, including our remaining uncontracted drillship construction project, prior to its deployment could adversely affect our results of operations and financial condition.

New technologies may cause our current drilling methods to become obsolete, resulting in an adverse effect on our business.

The offshore contract drilling industry is subject to the introduction of new drilling techniques and services using new technologies, some of which may be subject to patent protection.  As competitors and others use or develop new technologies, we may be placed at a competitive disadvantage and competitive pressures may force us to implement new technologies at substantial cost.  In addition, competitors may have greater financial, technical and personnel resources that allow them to benefit from technological advantages and implement new technologies before we can.  We may not be able to implement technologies on a timely basis or at a cost that is acceptable to us.

Our customers may be unable or unwilling to indemnify us.

Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts.  These risks are those associated with the loss of control of a well, such as blowout or cratering, the cost to regain control or redrill the well and associated pollution.  There can be no assurance, however, that these customers will necessarily be willing or financially able to indemnify us against all these risks.  Also, we may choose not to enforce these indemnities because of the nature of our relationship with some of our larger customers.

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 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 establishes a binding set of emission targets for GHGs, became binding on the countries that had ratified it.  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 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.

19

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 a negative 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 a negative 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.

We are subject to numerous governmental laws and regulations, including those that may impose significant costs and liability on us for environmental and natural resource damages.

Many aspects of our operations are affected by governmental laws and regulations that may relate directly or indirectly to the contract drilling and well servicing industries, including those requiring us to obtain and maintain specified permits or other governmental approvals and to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection.  Our operations and activities in the United States are subject to numerous environmental laws and regulations, including the Oil Pollution Act of 1990, the Outer Continental Shelf Lands Act, the Comprehensive Environmental Response, Compensation, and Liability Act and the International Convention for the Prevention of Pollution from Ships.  Additionally, other countries where we operate have adopted, and could in the future adopt additional, environmental laws and regulations covering the discharge of oil and other contaminants and protection of the environment that could be applicable to our operations.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and even criminal penalties, the imposition of remedial obligations, the denial or revocation of permits or other authorizations and the issuance of injunctions that may limit or prohibit our operations.  Laws and regulations protecting the environment have become more stringent in recent years and may in certain circumstances impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part.  These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time the acts were performed.  The application of these requirements, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or development drilling for oil and natural gas could materially limit future contract drilling opportunities or materially increase our costs or both.  In addition, we may be required to make significant capital expenditures to comply with laws and regulations or materially increase our costs or both.

Our ability to operate our rigs in the U.S. Gulf of Mexico could be restricted or made more costly by government regulation.

Hurricanes Katrina and Rita in 2005 and Hurricanes Gustav and Ike in 2008 caused damage to a number of rigs in the Gulf of Mexico. Rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs.  In May 2006 and April 2007, the MMS issued interim guidelines for jackup rig fitness requirements for the 2006 and 2007 hurricane seasons, effectively imposing new requirements on the offshore oil and natural gas industry in an attempt to increase the likelihood of survival of jackup rigs and other offshore drilling units during a hurricane. Effective June 2008, the MMS issued longer-term guidelines, generally consistent with the interim guidelines, for jackup rig fitness requirements during hurricane seasons. The June 2008 guidelines are scheduled to be effective through the 2013 hurricane season. As a result of these MMS guidelines, jackup rigs in the U.S. Gulf of Mexico are required to operate with a higher air gap (the space between the water level and the bottom of the rig’s hull) during the hurricane season, effectively reducing the water depth in which they can operate. The guidelines also provide for enhanced information and data requirements from oil and natural gas companies operating properties in the U.S. Gulf of Mexico. The MMS may take other steps that could increase the cost of operations or reduce the area of operations for jackup rigs, thus reducing their marketability. Implementation of the MMS guidelines or regulations may subject us to increased costs and limit the operational capabilities of our rigs.

20

A change in tax laws of any country in which we operate could result in a higher tax expense or a higher effective tax rate on our worldwide earnings.

We conduct our worldwide operations through various subsidiaries.  Tax laws and regulations are highly complex and subject to interpretation.  Consequently, we are subject to changing tax laws, treaties and regulations in and between countries in which we operate, including treaties between the United States and other nations.  Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred.  A change in these tax laws, treaties or regulations, including those in and involving the United States, or in the interpretation thereof, or in the valuation of our deferred tax assets, could result in a materially higher tax expense or a higher effective tax rate on our worldwide earnings.

As required by law, we file periodic tax returns that are subject to review and examination by various revenue agencies within the jurisdictions in which we operate.  We are currently contesting several tax assessments that could be material and may contest future assessments where we believe the assessments are in error.  We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments.

Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.

Certain of our employees in international markets are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation.  Efforts have been made from time to time to unionize other portions of our workforce.  In addition, we have been subjected to strikes or work stoppages and other labor disruptions in certain countries.  Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.

Certain legal obligations require us to contribute certain amounts to retirement funds and pension plans and restrict our ability to dismiss employees.  Future regulations or court interpretations established in the countries in which we conduct our operations could increase our costs and materially adversely affect our business, financial condition and results of operation.

Public health threats could have a material adverse effect on our operations and our financial results.

Public health threats, such as swine flu, bird flu, Severe Acute Respiratory Syndrome (SARS) and other highly communicable diseases, could adversely impact our operations, the operations of our clients and the global economy in general, including the worldwide demand for crude oil and natural gas and the level of demand for our services.  Any quarantine of personnel or inability to access our offices or rigs could adversely affect our operations.  Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, may materially impact operations and adversely affect our financial results.

Risk Factors About Our Recent Spin-Off

In connection with our spin-off of Seahawk, Seahawk agreed to indemnify us for certain liabilities. However, there can be no assurance that the indemnity will be sufficient to insure us against the full amount of such liabilities, or that Seahawk’s ability to satisfy its indemnification obligations will not be impaired in the future.

In August 2009, we completed the spin-off of Seahawk, which holds the assets and liabilities that were associated with our mat-supported jackup rig business.  Pursuant to a master separation agreement entered into in connection with the spin-off, Seahawk agreed to indemnify us from certain liabilities.  However, third parties could seek to hold us responsible for any of the liabilities for which Seahawk has agreed to be responsible, and there can be no assurance that the indemnity from Seahawk will be sufficient to protect us against the full amount of such liabilities, or that Seahawk will be able to fully satisfy its indemnification obligations.  Moreover, even if we ultimately succeed in recovering from Seahawk any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves.  In some cases, we have agreed to advance expenses or to guarantee obligations related to liabilities Seahawk has agreed to retain.  Each of these risks could adversely affect our results of operations and financial condition.

21

      In 2006, 2007, and 2009, Seahawk received tax assessments from the Mexican government related to the operations of certain of Seahawk’s subsidiaries. Seahawk is responsible for these assessments following the spin-off.  Pursuant to local statutory requirements, Seahawk has provided and may provide additional surety bonds or other suitable collateral to contest these assessments.  Pursuant to a tax support agreement between us and Seahawk, we have agreed, at Seahawk’s request, to guarantee or indemnify the issuer of any such surety bonds or other collateral issued for Seahawk’s account in respect of such Mexican tax assessments made prior to the spin-off date.  The amount of such bonds or other collateral could total up to approximately $143.0 million based on current exchange rates.  Beginning on July 31, 2012, on each subsequent anniversary thereafter, and on August 24, 2015, Seahawk will be required to provide substitute credit support for a portion of the collateral guaranteed or indemnified by us, so that our obligations are terminated in their entirety by August 24, 2015.  Pursuant to the tax support agreement, Seahawk is required to pay us a fee based on the actual credit support provided.  As of December 31, 2009, we had not provided any guarantee or indemnification for any surety bonds or other collateral under the tax support agreement.

If certain internal restructuring transactions and the spin-off of our mat-supported jackup rig business are determined to be taxable for U.S. federal income tax purposes, we and our stockholders that are subject to U.S. federal income tax could incur significant U.S. federal income tax liabilities.

Certain internal restructuring transactions were undertaken in preparation for the spin-off of our mat-supported jackup rig business in 2009. These transactions are complex and could cause us to incur significant tax liabilities. We received a ruling from the Internal Revenue Service that these transactions and the spin-off qualified for favorable tax treatment. In addition, we obtained an opinion of tax counsel confirming the favorable tax treatment of these transactions and the spin-off. The ruling and the opinion rely on certain facts, assumptions, representations and undertakings from us regarding the past and future conduct of our businesses and other matters. If any of these are incorrect or not otherwise satisfied, then we and our stockholders may not be able to rely on the ruling or the opinion and could be subject to significant tax liabilities. Notwithstanding the ruling and the opinion, the Internal Revenue Service could determine on audit that the spin-off or the internal restructuring transactions should be treated as taxable transactions if it determines that any of these facts, assumptions, representations or undertakings are not correct or have been violated, or if the spin-off should become taxable for other reasons, including as a result of significant changes in stock ownership after the spin-off.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

Our property consists primarily of mobile offshore drilling rigs and ancillary equipment, most of which we own. Two of our rigs are pledged with respect to our notes guaranteed by the United States Maritime Administration. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in Item 7 of this annual report.

We own or lease office and operating facilities in Houston, Texas and in Angola, Brazil, France, and several additional international locations.

We incorporate by reference in response to this item the information set forth in Item 1 and Item 7 of this annual report and the information set forth in Notes 4 and 5 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report.

ITEM 3.  LEGAL PROCEEDINGS

We incorporate by reference in response to this item the information set forth in Note 13 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report.

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ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

Executive Officers of Registrant

We have presented below information about our executive officers as of February 19, 2010. Officers are appointed annually by the Board of Directors and serve until their successors are chosen or until their resignation or removal.

Name	Age	Position
Louis A. Raspino	57	President, Chief Executive Officer
Brian C. Voegele	49	Senior Vice President and Chief Financial Officer
Lonnie D. Bane	51	Senior Vice President, Human Resources and Administration
W. Gregory Looser	40	Senior Vice President and Chief Administrative Officer
Kevin C. Robert	51	Senior Vice President, Marketing and Business Development
Imran (Ron) Toufeeq	53	Senior Vice President, Operations, Asset Management and Engineering

Louis A. Raspino was named President, Chief Executive Officer and a Director in June 2005. He joined us in December 2003 as Executive Vice President and Chief Financial Officer. From July 2001 until December 2003, he served as Senior Vice President, Finance and Chief Financial Officer of Grant Prideco, Inc. From February 1999 until March 2001, he held various senior financial positions, including Vice President of Finance for Halliburton Company. From October 1997 until July 1998, he was a Senior Vice President at Burlington Resources, Inc. From 1978 until its merger with Burlington Resources, Inc. in 1997, he held a variety of increasingly responsible positions at Louisiana Land and Exploration Company, most recently as Senior Vice President, Finance and Administration and Chief Financial Officer. Mr. Raspino also is a Director of Dresser-Rand Group Inc.

Brian C. Voegele joined us in December 2005 and became our Senior Vice President and Chief Financial Officer in January 2006. From June 2005 through November 2005, he served as Senior Vice President, Chief Financial Officer, Treasurer and Secretary of Bristow Group (formerly Offshore Logistics, Inc.). From July 1989 until January 2005, he held various senior management positions at Transocean Inc., including Vice President of Corporate Planning and Development, Vice President of Finance, and Vice President of Tax.  From 1983 to 1989, Mr. Voegele worked at Arthur Young & Co. (now Ernst & Young LLP), where he ultimately served as Tax Manager.  Mr. Voegele holds a license as a CPA.

Lonnie D. Bane was named Senior Vice President, Human Resources and Administration in January 2005. He previously served as Vice President, Human Resources since June 2004. From July 2000 until May 2003, he served as Senior Vice President, Human Resources of America West Airlines, Inc. From July 1998 until July 2000, he held various senior management positions, including Senior Vice President, Human Resources at Corporate Express, Inc. From February 1996 until July 1998, Mr. Bane served as Senior Vice President, Human Resources for CEMEX, S.A. de C.V. From 1994 until 1996, he was a Vice President, Human Resources at Allied Signal Corporation. From 1987 until 1994, he held various management positions at Mobil Oil Corporation.

W. Gregory Looser became our Senior Vice President and Chief Administrative Officer in August 2009.  Prior to being named Chief Administrative Officer, he was Senior Vice President – Legal, Information Strategy, General Counsel and Secretary since June 2008.  He previously served as Senior Vice President, General Counsel and Secretary from January 2005 until June 2008, as Vice President, General Counsel and Secretary from December 2003 until January 2005 and as Assistant General Counsel from May 1999 until December 2003.  Prior to that time, Mr. Looser was with the law firm of Bracewell & Guiliani LLP in Houston, Texas.

Kevin C. Robert was named Vice President, Marketing in March 2005 and became Senior Vice President, Marketing and Business Development in May 2006. Prior to joining us, from June 2002 to February 2005, Mr. Robert worked for Samsung Heavy Industries as the Vice President, EPIC Contracts. From January 2001 through September 2001, Mr. Robert was employed by Marine Drilling Companies, Inc. as the Vice President, Marketing. When we acquired Marine in September 2001, he became our Director of Business Development, where he served until June 2002. From November 1997 through December 2000, Mr. Robert was Managing Member of Maverick Offshore L.L.C. From January 1981 to November 1997, Mr. Robert was employed by Conoco Inc.

Imran (Ron) Toufeeq was named Senior Vice President, Operations, Asset Management and Engineering in August 2009.  Mr. Toufeeq joined us in March 2004 as Vice President — Engineering & Technical Services and was appointed as Senior Vice President, Asset Management and Engineering in February 2008. Previously, he was employed for 20 years by R&B Falcon, a drilling contractor, ultimately serving as Senior Vice President of Operations.

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PART II

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

Our common stock is listed on the New York Stock Exchange under the symbol “PDE.” As of February 15, 2010, there were approximately 1,060 stockholders of record. The following table presents the range of high and low sales prices of our common stock on the NYSE for the periods shown:

	Price
	High		Low
2008
First Quarter	$	37.24	$	28.35
Second Quarter		48.86		34.36
Third Quarter		47.00		27.18
Fourth Quarter		29.48		11.38
2009
First Quarter	$	20.90	$	14.40
Second Quarter		27.11		17.10
Third Quarter		32.01		22.29
Fourth Quarter		34.67		28.31

We have not paid any cash dividends on our common stock since becoming a publicly held corporation in September 1988. We currently do not have any plans to pay cash dividends on our common stock. In addition, in the event we elect to pay cash dividends in the future, our ability to pay such dividends could be limited by our existing financing arrangements.

Unregistered Sales of Equity Securities

None.

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share	Total Number of Shares Purchased as Part of a Publicly Announced Plan (2)	Maximum Number of Shares That May Yet Be Purchased Under the Plan (2)
October 1-31, 2009	-	-	N/A	N/A
November 1-30, 2009	-	-	N/A	N/A
December 1-31, 2009	1,374	$          32.28	N/A	N/A
Total	1,374	$          32.28	N/A	N/A

_____________

(1)	Represents the surrender of shares of common stock to satisfy statutory minimum tax withholding obligations in connection with the vesting of restricted stock awards issued to employees under our stockholder-approved long-term incentive plan.
(2)	We did not have at any time during the quarter, and currently do not have, a share repurchase program in place.

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ITEM 6.  SELECTED FINANCIAL DATA

We have derived the following selected consolidated financial information as of December 31, 2009 and 2008, and for the years ended December 31, 2009, 2008 and 2007, from our audited consolidated financial statements included in Item 8 of this annual report. We have derived the selected consolidated financial information as of December 31, 2007, 2006 and 2005 and for the years ended December 31, 2006 and 2005 from consolidated financial information included our annual report on Form 10-K for the year ended December 31, 2008. We have previously reclassified the historical results of operations of our former Latin America Land and E&P Services segments, three tender assist rigs, and Eastern Hemisphere land rig operations, and for 2009 we reclassified the historical results of operations of our mat-supported jackup business, to discontinued operations.  See Note 2 to Notes to the Consolidated Financial Statements in Item 8 of this annual report. The selected consolidated financial information below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this annual report and our audited consolidated financial statements and related notes included in Item 8 of this annual report.

	Year Ended December 31,
	2009			2008			2007			2006			2005
	(In millions, except per share amounts)
Statement of Operations Data:
Revenues excluding reimbursable revenues	$	1,563.5		$	1,664.7		$	1,294.2		$	885.9		$	817.5
Reimbursable revenues		30.7			37.9			34.8			22.7			11.4
Operating costs, excluding depreciation and amortization		828.3			766.5			618.6			587.9			555.2
Reimbursable costs		27.3			34.9			30.8			19.4			6.7
Depreciation and amortization		159.0			147.3			153.1			129.4			119.4
General and administrative, excluding depreciation and amortization		110.5			126.7			138.1			105.8			80.9
Department of Justice and Securities and Exchange Commission fines		56.2			-			-			-			-
Impairment charges		-			-			-			-			1.0
Loss (gain) on sales of assets, net		(0.4	)		0.1			(29.8	)		(27.9	)		(35.1	)
Earnings from operations		413.3			627.1			418.2			94.0			100.8
Interest expense, net of amounts capitalized		(0.1	)		(20.0	)		(83.1	)		(89.0	)		(97.0	)
Refinancing charges		-			(2.3	)		-			-			-
Interest income		3.0			16.8			14.3			4.2			1.8
Other income (expense), net		(4.1	)		20.6			(2.7	)		2.5			2.4
Income from continuing operations before income taxes		412.1			642.2			346.7			11.7			8.0
Income taxes		(71.8	)		(133.5	)		(86.9	)		(13.0	)		(8.5	)
Income from continuing operations, net of tax	$	340.3		$	508.7		$	259.8		$	(1.3	)	$	(0.5	)
Income from continuing operations per share:
Basic	$	1.93		$	2.95		$	1.54		$	(0.03	)	$	(0.13	)
Diluted	$	1.92		$	2.89		$	1.51		$	(0.03	)	$	(0.13	)
Shares used in per share calculations:
Basic		173.7			170.6			165.6			162.8			152.5
Diluted		174.0			175.2			178.1			162.8			152.5

	December 31,
	2009		2008		2007		2006		2005
	(In millions)
Balance Sheet Data:
Working capital	$	661.8	$	849.6	$	888.0	$	293.1	$	213.8
Property and equipment, net		4,890.3		4,592.9		4,021.4		4,000.3		3,181.7
Total assets		6,142.9		6,069.0		5,615.6		5,097.6		4,086.5
Long-term debt, net of current portion		1,161.7		692.9		1,111.9		1,280.2		1,162.7
Stockholders’ equity		4,257.8		4,400.0		3,474.0		2,643.5		2,275.4

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with “Financial Statement and Supplementary Data” in Item 8 of this annual report. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A and elsewhere in this annual report. See “Forward-Looking Statements” below.

Overview

We are one of the world’s largest offshore drilling contractors. As of February 19, 2010, we operated a fleet of 23 rigs, consisting of two deepwater drillships, 12 semisubmersible rigs, seven independent leg jackups and two managed deepwater drilling rigs. We also have four deepwater drillships under construction. Our customers include major integrated oil and natural gas companies, state-owned national oil companies and independent oil and natural gas companies. Our competitors range from large international companies offering a wide range of drilling services to smaller companies focused on more specific geographic or technological areas.

We are continuing to increase our emphasis on deepwater drilling. Although crude oil prices have declined from the record levels reached in mid-2008, we believe the long-term prospects for deepwater drilling are positive given that the expected growth in oil consumption from developing nations, limited growth in crude oil supplies and high depletion rates of mature oil fields, together with geologic successes, improving access to promising offshore areas and new, more efficient technologies, will continue to be catalysts for the long-term exploration and development of deepwater fields. Since 2005, we have invested or committed to invest over $3.7 billion in the expansion of our deepwater fleet, including four new ultra-deepwater drillships under construction. Three of the drillships have multi-year contracts at favorable rates, with two scheduled to work in the strategically important deepwater U.S. Gulf of Mexico, which, in addition to our operations in Brazil and West Africa, provides us with exposure to all three of the world’s most active deepwater basins. Since 2005, we also have disposed of non-core assets, generating $1.6 billion in proceeds, enabling us to increasingly focus our financial and human capital on deepwater drilling. In addition, on August 24, 2009, we completed the spin-off of Seahawk Drilling, Inc., which holds the assets and liabilities that were associated with our mat-supported jackup rig business.

Our customers reduced exploration and development spending in 2009, especially in midwater and shallow water drilling programs, due to the economic downturn and decline in crude oil prices.  We anticipate that deepwater activity will outperform other drilling sectors due to the longer nature of deepwater field development, more favorable drilling economics and the tendency for deepwater drilling programs to be more insulated to short-term commodity price fluctuations.  An increasing focus on deepwater prospects by national oil companies, whose activities are less sensitive to general economic factors, serve to provide further stability in the deepwater sector.  Our contract backlog at December 31, 2009 totals $6.9 billion and is comprised primarily of contracts for deepwater rigs with large integrated oil and national oil companies possessing long-term development plans.  Our backlog, together with our existing cash on hand and borrowing availability under our revolving credit facility, are expected to provide sufficient financial resources to meet existing obligations through the current economic global uncertainty.

Recent Developments

Spin-off of Mat-Supported Jackup Business

On August 24, 2009, we completed the spin-off of Seahawk, which holds the assets and liabilities that were associated with our mat-supported jackup rig business.  In the spin-off, our stockholders received 100% (approximately 11.6 million shares) of the outstanding common stock of Seahawk by way of a pro rata stock dividend.  Each of our stockholders of record at the close of business on August 14, 2009 received one share of Seahawk common stock for every 15 shares of our common stock held by such stockholder and cash in lieu of any fractional shares of Seahawk common stock to which such stockholder otherwise would have been entitled.  In connection with the spin-off, we made a cash contribution to Seahawk of approximately $47.3 million to achieve a targeted working capital for Seahawk as of May 31, 2009 of $85 million.  We and Seahawk also agreed to indemnify each other for certain liabilities that may arise or be incurred in the future attributable to our respective businesses.

26

Issuance of 8 ½% Senior Notes due 2019

On June 2, 2009, we completed an offering of $500.0 million aggregate principal amount of 8 1/2% Senior Notes due 2019. We are using the net proceeds from the offering of $492.4 million for general corporate purposes, which include payments with respect to our four drillships under construction and other capital expenditures.

Contract Termination

In March 2009, we accelerated a planned inspection on our midwater semisubmersible Pride Venezuela. The rig had been working offshore Angola. An inspection of a section of the rig’s hull revealed an unacceptable level of corrosion, which required a dry-dock facility to conduct the repairs. The hull repairs, along with other maintenance and repairs to the rig, were expected to require most of the remaining term of the rig’s then-existing contract, which had been expected to conclude in March 2010. Consequently, in May 2009 we and the customer mutually agreed to the termination of the remaining term of the contract. The rig was mobilized to a shipyard in Dubai for further evaluation and completion of a rig refurbishment project.  The rig refurbishment project was initiated in December and includes significant steel replacement and refurbishment of drilling and other rig equipment.  We expect the project to be completed during the second quarter of 2010.

Investments in Deepwater Fleet

In January 2008, we entered into a five-year contract with respect to the Deep Ocean Mendocino, our drillship under construction with a scheduled delivery in the first quarter of 2011. The drilling contract is expected to commence in the second quarter of 2011 following the completion of shipyard construction, mobilization of the rig to an initial operating location and customer acceptance testing. The construction agreement with the shipyard provides for an aggregate fixed purchase price of approximately $635 million. Including amounts already paid, commissioning and testing, we expect the total project cost to be approximately $725 million, excluding capitalized interest. Through December 31, 2009, we have spent approximately $344 million on this construction project.

In January 2008, we entered into a five-year contract for drilling operations in the U.S. Gulf of Mexico with respect to the Deep Ocean Ascension, our drillship under construction, which we acquired from Lexton Shipping Ltd. Scheduled delivery of this rig is in the first quarter of 2010.  Work on the client’s behalf is expected to commence mid-2010 following the completion of shipyard construction, mobilization of the rig to the U.S. Gulf of Mexico and customer acceptance testing. In connection with the contract, the drillship is being modified from the original design to provide enhanced capabilities designed to allow our clients to conduct subsea construction activities and other simultaneous activities, while drilling or completing the well. The construction agreement with the shipyard provides for an aggregate fixed purchase price of approximately $650 million. Including the above-mentioned modifications, amounts already paid, commissioning and testing, we expect the total project cost to be approximately $750 million, excluding capitalized interest. Through December 31, 2009, we have spent approximately $436 million on this construction project.

In April 2008, we entered into a five-year contract with respect to the Deep Ocean Clarion, our drillship under construction with a scheduled delivery in the third quarter of 2010. The drilling contract is expected to commence in the beginning of the first quarter of 2011 following the completion of shipyard construction, mobilization of the rig to an initial operating location and customer acceptance testing. In connection with the contract, the drillship is being modified from the original design to provide enhanced capabilities designed to allow our clients to conduct subsea construction activities and other simultaneous activities, while drilling or completing the well. The construction agreement with the shipyard provides for an aggregate fixed purchase price of approximately $612 million. Including the above-mentioned modifications, amounts already paid, commissioning and testing, we expect the total project cost to be approximately $715 million, excluding capitalized interest. Through December 31, 2009, we have spent approximately $463 million on this construction project. Also, while we have previously purchased a license to equip the rig for dual-activity use, the rig will not initially be functional as a dual-activity rig, but can be modified to add this functionality in the future.

In August 2008, we entered into an agreement for the construction of a fourth ultra-deepwater drillship, named Deep Ocean Molokai to be delivered to us in the fourth quarter of 2011. The agreement provides for an aggregate fixed purchase price of approximately $655 million. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages for delays during certain periods. Through December 31, 2009, we have spent approximately $280 million on this construction project. Including commissioning and testing, we expect the total project cost to be approximately $755 million, excluding capitalized interest. Although we currently do not have a drilling contract for this drillship, we expect that the anticipated long-term demand for deepwater drilling capacity in established and emerging basins should provide us with a number of opportunities to contract the rig prior to its delivery date.

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There are risks of delay inherent in any major shipyard project, including work stoppages, disputes, financial and other difficulties encountered by the shipyard, and adverse weather conditions. For our ultra-deepwater drillships under construction, we have attempted to mitigate risks of delay by selecting the same shipyard for all four construction projects with fixed-fee contracts, although some of the other risks are more concentrated.

Dispositions

In February 2008, we completed the sale of our fleet of three self-erecting, tender-assist rigs for $213 million in cash. We operated one of the rigs until mid-April 2009, when we transitioned the operations of that rig to the owner.

In May 2008, we sold our entire fleet of platform rigs and related land, buildings and equipment for $66 million in cash. In connection with the sale, we entered into lease agreements with the buyer to operate two platform rigs until their existing contracts are completed.  In March 2009, the contract for one of these rigs was canceled and the rig was subsequently transitioned to the buyer at the beginning of April 2009.  A contract extension was granted for the remaining rig, which we continued to operate until the spin-off of Seahawk in August 2009 as this contract was included in Seahawk’s business. The leases required us to pay to the buyer all revenues from the operation of the rigs, less operating costs and a small per day management fee, which we retained.

In July 2008, we entered into agreements to sell our Eastern Hemisphere land rig business, which constituted our only remaining land drilling operations, for $95 million in cash. The sale of all but one of the rigs closed in the fourth quarter of 2008. We leased the remaining rig to the buyer until the sale of that rig closed, which occurred in the second quarter of 2009.

We have reclassified the historical results of operations of our former Latin America Land and E&P Services segments, three tender-assist rigs, Eastern Hemisphere land rig operations and mat-supported jackup business to discontinued operations.  

Unless noted otherwise, the discussion and analysis that follows relates to our continuing operations only.

Loss of Pride Wyoming

In September 2008, the Pride Wyoming, a 250-foot slot-type jackup rig owned by Seahawk and operating in the U.S. Gulf of Mexico, was deemed a total loss for insurance purposes after it was severely damaged and sank as a result of Hurricane Ike. All proceeds related to the insured value of the rig were received in 2008. Costs for removal of the wreckage are expected to be covered by our insurance.  Under the master separation agreement between us and Seahawk, Seahawk will be responsible for any removal costs, legal settlements and legal costs associated with the Pride Wyoming not covered by insurance.  At Seahawk's request, we will be required to finance, on a revolving basis, all of the costs for removal of the wreckage and salvage operations until receipt of insurance proceeds.  As of December 31, 2009, there were no amounts outstanding under this arrangement.

FCPA Investigation

During the course of an internal audit and investigation relating to certain of our Latin American operations, our management and internal audit department received allegations of improper payments to foreign government officials. In February 2006, the Audit Committee of our Board of Directors assumed direct responsibility over the investigation and retained independent outside counsel to investigate the allegations, as well as corresponding accounting entries and internal control issues, and to advise the Audit Committee.

The investigation has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.

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The Audit Committee, through independent outside counsel, has undertaken a review of our compliance with the FCPA in certain of our other international operations.  This review has found evidence suggesting that during the period from 2001 through 2006 payments were made directly or indirectly to government officials in Saudi Arabia, Kazakhstan, Brazil, Nigeria, Libya, Angola and the Republic of the Congo in connection with clearing rigs or equipment through customs or resolving outstanding issues with customs, immigration, tax, licensing or merchant marine authorities in those countries. In addition, this review has found evidence suggesting that in 2003 payments were made to one or more third parties with the intent that they would be transferred to a government official in India for the purpose of resolving a customs dispute related to the importation of one of our jackup rigs. The evidence suggests that the aggregate amount of payments referred to in this paragraph is less than $2.5 million. In addition, the U.S. Department of Justice (“DOJ”) has asked us to provide information with respect to (a) our relationships with a freight and customs agent and (b) our importation of rigs into Nigeria.

The investigation of the matters described above and the Audit Committee’s compliance review are substantially complete. Our management and the Audit Committee of our Board of Directors believe it likely that then members of our senior operations management either were aware, or should have been aware, that improper payments to foreign government officials were made or proposed to be made. Our former Chief Operating Officer resigned as Chief Operating Officer effective on May 31, 2006 and has elected to retire from the company, although he will remain an employee, but not an officer, until the completion of the investigation and related matters to assist us with the investigation and to be available for consultation and to answer questions relating to our business.  His retirement benefits will be subject to the determination by our Audit Committee or our Board of Directors that it does not have cause (as defined in his retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.

We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the DOJ and the SEC, and we have cooperated and continue to cooperate with these authorities.  For any violations of the FCPA, we may be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 per violation and a company that knowingly commits a violation can be fined up to $25 million per violation. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.

We are engaged in discussions with the DOJ and the SEC regarding a potential negotiated resolution of these matters, which could be settled during 2010 and which, as described above, could involve a significant payment by us.  We believe that it is likely that any settlement will include both criminal and civil sanctions.  We have accrued $56.2 million in anticipation of a possible resolution with the DOJ and the SEC of potential liabilities under the FCPA. This accrual represents our best estimate of potential fines, penalties and disgorgement related to such resolution. For tax purposes, fines and penalties are not deductible. The monetary sanctions ultimately paid by us to resolve these issues, whether imposed on us or agreed to by settlement, may exceed the amount of the accrual.  There can be no assurance that our discussions with the DOJ and SEC will result in a final settlement of any or all of these issues or, if a settlement is reached, the timing of any such settlement or that the terms of any such settlement would not have a material adverse effect on us.

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       We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests.  We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our company.  For additional information regarding a stockholder demand letter with respect to these matters, please see the discussion under “Demand Letter” in Note 13 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report.  In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets.  While we have made an accrual in anticipation of a possible resolution with the DOJ and SEC as discussed above, no amounts have been accrued related to any potential fines, sanctions, claims or other penalties referenced in this paragraph, which could be material individually or in the aggregate.

Although, as discussed above, we are currently in discussions with the DOJ and the SEC regarding a possible resolution of potential liability under the FCPA, we cannot currently predict what, if any, actions may be taken by the DOJ, the SEC, any other applicable government or other authorities or our customers or other third parties or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.

Our Business

We provide contract drilling services to major integrated, government-owned and independent oil and natural gas companies throughout the world. Our drilling fleet competes on a global basis, as offshore rigs generally are highly mobile and may be moved from one region to another in response to demand. While the cost of moving a rig and the availability of rig-moving vessels may cause the supply and demand balance to vary somewhat between regions, significant variations between regions do not tend to persist long-term because of rig mobility. Key factors in determining which qualified contractor is awarded a contract include pricing, safety performance and operations competency.  Rig availability, location and technical ability can also be key factors in the determination. Currently, all of our drilling contracts with our customers are on a dayrate basis, where we charge the customer a fixed amount per day regardless of the number of days needed to drill the well. We provide the rigs and drilling crews and are responsible for the payment of rig operating and maintenance expenses. Our customer bears the economic risk and benefit relative to the geologic success of the wells to be drilled.

The markets for our drilling services have historically been highly cyclical. Our operating results are significantly affected by the level of energy industry spending for the exploration and development of crude oil and natural gas reserves. Oil and natural gas companies’ exploration and development drilling programs drive the demand for drilling services. These drilling programs are affected by a number of factors, including oil and natural gas companies’ expectations regarding crude oil and natural gas prices. Some drilling programs are influenced by short-term expectations, such as shallow water drilling programs in the U.S. Gulf of Mexico and the Middle East, while others, especially deepwater drilling programs, are typically subject to a longer term view of crude oil prices. Other drivers include anticipated production levels, worldwide demand for crude oil and natural gas products and many other factors. Access to quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments also affect our customers’ drilling programs. Crude oil and natural gas prices are highly volatile, which has historically led to significant fluctuations in expenditures by our customers for oil and natural gas drilling services. Variations in market conditions during the cycle impact us in different ways depending primarily on the length of drilling contracts in different regions. For example, contracts for jackup rigs in certain shallow water markets are shorter term, so a deterioration or improvement in market conditions tends to quickly impact revenues and cash flows from those operations. Contracts in deepwater and other international offshore markets tend to be longer term, so a change in market conditions tends to have a delayed impact. Accordingly, short-term changes in market conditions may have minimal impact on revenues and cash flows from those operations unless the timing of contract renewals takes place during the short-term changes in the market.

Our revenues depend principally upon the number of our available rigs, the number of days these rigs are utilized and the contract dayrates received. The number of days our rigs are utilized and the contract dayrates received are largely dependent upon the balance of supply of drilling rigs and demand for drilling services for the different rig classes we operate, as well as our rigs’ operational performance, including mechanical efficiency. The number of rigs we have available may increase or decrease as a result of the acquisition or disposal of rigs, the construction of new rigs, the number of rigs being upgraded or repaired or undergoing standard periodic surveys or routine maintenance at any time and the number of rigs idled during periods of oversupply in the market or when we are unable to contract our rigs at economical rates.  In order to improve utilization or realize higher contract dayrates, we may mobilize our rigs from one geographic region to another for which we may receive a mobilization fee from the client. The mobilization fee is intended to cover the cost of moving the rig and, during periods when rigs are in short supply, may provide revenues in excess of the cost to mobilize the unit. Mobilization fees are deferred and recognized as revenue over the term of the drilling contract.

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We organize our reportable segments based on the water depth operating capabilities of our drilling rigs. Our reportable segments include Deepwater, which consists of our rigs capable of drilling in water depths of 4,500 feet and greater; Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less; and Independent Leg Jackups, which consists of our rigs capable of operating in water depths up to 300 feet. We also manage the drilling operations for deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations.

Our earnings from operations are primarily affected by revenues, utilization of our fleet and the cost of labor, repairs, insurance and maintenance. Many of our drilling contracts covering multiple years allow us to adjust the dayrates charged to our customer based on changes in operating costs, such as increases in labor costs, maintenance and repair costs and insurance costs. Some of our costs are fixed in nature or do not vary at the same time or to the same degree as changes in revenue. For instance, if a rig is expected to be idle between contracts and earn no revenue, we may maintain our rig crew, which reduces our earnings as we cannot fully offset the impact of the lost revenues with reductions in operating costs. In addition, some drilling contracts provide for the payment of bonus revenues, representing a percentage of the rig’s contract dayrate and based on the rig meeting defined operations performance during a period.

Our industry has traditionally been affected by shortages of, and competition for, skilled rig crew personnel during periods of high levels of activity. Even as overall industry activity declines, we expect these personnel shortages to continue, especially in the deepwater segment, due to the number of newbuild deepwater rigs expected to be delivered through 2013 and the need for highly skilled personnel to operate these rigs. To better retain and attract skilled rig personnel, we offer competitive compensation programs and have increased our focus on training and management development programs. Labor costs continued to increase in 2009, especially for skilled personnel in certain geographic locations, although the more challenging business environment characterized by reduced offshore activity slowed the rate of increase of such costs during the year. Labor costs are expected to increase further in 2010, most notably in the deepwater segment.

Beginning in 2005, demand for contract drilling services experienced a significant increase, resulting in increased demand for oilfield equipment and spare parts. This increased demand, when coupled with the consolidation of equipment suppliers, resulted in longer order lead times to obtain critical spares and other critical equipment components essential to our business, along with higher repair and maintenance costs and longer out-of-service time for major repair and upgrade projects. We maintain higher levels of critical spares in an effort to minimize unplanned downtime. With the decline in prices during 2009 for steel and other key inputs and the decline in the level of business activity, we believe that some softening of lead times and pricing for spare parts and equipment is possible for the foreseeable future. The amount and timing of such softening will be affected by our suppliers’ level of backlog and the number of remaining newbuilds, which are expected to increase in 2010 due especially to expanding deepwater rig needs in Brazil.

The decline in crude oil prices that began in late 2008, following the onset of the global financial crisis, deteriorating global economic fundamentals and the resulting decline in crude oil demand in a number of the world’s largest oil consuming nations, had a negative impact in 2009 on customer demand for offshore rigs. Crude oil prices averaged approximately $62 per barrel during 2009 compared to $114 per barrel in 2008. The lower price along with the uncertainty of prices in the near-term contributed heavily to a significant reduction in planned 2009 offshore drilling expenditures by our customers. Worldwide offshore fleet utilization declined to its lowest level since early 2000, to approximately 75% at December 31, 2009 as compared to 87% at December 31, 2008. This decline was more pronounced in exploration activities, which are by their nature shorter term projects. Deepwater drilling activity displayed more resilience during the more challenging business environment in 2009 relative to other offshore drilling activities, especially for projects currently in a development phase.  This is due to the long-term planning horizon common among our customers when engaged in deepwater development programs. Utilization for the industry’s deepwater fleet has historically been less sensitive to the extreme fluctuations as experienced within the shallow water market even during market downturns. Although crude oil prices during early 2010 have at times closed above $80 per barrel, representing a better than 140% improvement since declining to a 2009 low of $34 per barrel in February 2009, many clients remain cautious in early 2010 regarding offshore spending and are postponing some drilling programs to later years while others continue to engage in subletting of rigs in an effort to reduce their capital commitments during a period of price uncertainty.  Historically, greater confidence by our customers in a sustainable range for crude oil prices has led to increased exploration and production spending, creating a stronger environment for offshore drilling services. Crude oil prices have remained above $60 per barrel since August 2009 and have averaged $71 per barrel from May 2009 through January 2010. We believe a business environment characterized by increased price sustainability above $60 per barrel should lead to increased client exploration and production spending in 2010 relative to spending levels in 2009. However, the timing of the increased spending may not be evident until improvement in oil market fundamentals are present, including stronger evidence of global economic expansion and reviving crude oil demand.

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We believe that long-term market conditions for offshore drilling services are supported by sound fundamental factors and that demand should produce attractive opportunities for our deepwater rigs, including those units under construction.  We expect the long-term global demand for deepwater contract drilling services to be driven by the return of expanding worldwide demand for crude oil and natural gas as global economic growth returns, an increased focus by oil and natural gas companies on deepwater offshore prospects, and increased global participation by national oil companies. Customer requirements for deepwater drilling capacity have grown since 2005, as the successful results in exploration drilling conducted over the past several years have led to numerous prolonged field development programs around the world, placing deepwater assets in limited supply through 2010. We believe that positive long-term economic trends and increased demand for crude oil will lead to a sustainable trading range for crude oil prices in the future and increased exploration and production spending. Should recent global economic trends continue to strengthen, providing support for improving crude oil price fundamentals, we believe spending by our clients will increase in 2010 relative to 2009 spending levels. A recent survey of 387 global integrated, independent and national oil companies conducted by Barclays Capital concluded that total exploration and production spending in 2010 could increase by 11% compared to an estimated 15% decline during 2009. In addition, the survey estimates that 50% of respondents expect to increase the share of total offshore spending dedicated to deepwater drilling in 2010. Geological successes in exploratory markets, such as the numerous discoveries to date in the pre-salt formation offshore Brazil, the lower tertiary trend in the U.S. Gulf of Mexico and deeper waters offshore Angola, along with the continued development of a number of deepwater projects in each of these regions, are expected to produce growing demand from clients for deepwater rigs. During 2009, clients announced a record 25 deepwater discoveries covering an expanding number of offshore basins, such as Ghana and Sierra Leone, further supporting the long-term sustainability of deepwater drilling demand. In addition, international oil companies are experiencing greater access to other promising areas offshore, such as India, Malaysia, Australia, Mexico and the Black Sea. The combination of drilling successes, greater access to offshore basins and continued advances in offshore technology which support increased efficiency in field development efforts, including parallel drilling activities, are expected to further support the improving long-term outlook for deepwater rig demand.

Our deepwater fleet currently operates in Brazil, West Africa and the Mediterranean Sea, and we expect to increase the breadth of our operations in the strategically important U.S. Gulf of Mexico region in 2010 with the delivery of the Deep Ocean Ascension and Deep Ocean Clarion, two of our four deepwater drillships currently under construction.  Including rig days for our drillships under construction, based upon their scheduled delivery dates, we have 100% of our available rig days for our deepwater fleet contracted in 2010, 80% in 2011, 67% in 2012 and 55% in 2013. Since a steady increase in customer demand for deepwater drilling rigs began in 2005, substantially all of the industry’s fleet of 122 units capable of operating in water depths of 4,500 feet and greater remained under contract through 2009, the beneficiaries of large contract backlogs. The high customer demand led to a steep rise in deepwater rig dayrates, which peaked above $600,000 per day for some multi-year contracts awarded in 2008. Although declines in dayrates have occurred from peak levels, dayrates for deepwater rigs capable of drilling in greater than 7,000 feet of water and available in 2010 have remained above $400,000 per day. These dayrates have been supported by strong geologic success, especially in Brazil, West Africa, the U.S. Gulf of Mexico, and in some of the new and emerging deepwater regions, which has led to a growing number of commercial discoveries.  The drilling success has been most notable offshore Brazil, where exploration drilling in the country’s prolific subsalt formation has found numerous crude oil deposits of significant size residing in up to 7,000 feet of water in the Santos Basin. The successful drilling results and aggressive exploration calendar have resulted in an announced $62 billion increase in planned exploration and production expenditures by Petrobras, the national oil company of Brazil, to an estimated $105 billion between 2009 through 2013 to support development of the subsalt formation and other global interests. The expansion includes the need for up to 28 incremental deepwater rigs to be deployed in the numerous subsalt fields discovered to date, with 19 of the incremental rig needs offered to international contract drillers.  We are currently evaluating the opportunity to participate in the deepwater expansion offshore Brazil, but have not currently reached a conclusion regarding the balance between appropriate return criteria and numerous risk factors associated with the expansion program, including a requirement that all 19 of the deepwater assets be constructed by shipyards in Brazil. A similar subsalt geologic trend has been identified offshore West Africa, which could lead to increased deepwater drilling in the future.

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In addition, deepwater drilling economics have been aided in recent years by an expectation of higher average crude oil prices, supported by global economic expansion and an increased number of deepwater discoveries containing large volumes of hydrocarbons.  These improving factors associated with deepwater activity have produced a growing base of development programs requiring multiple years to complete and resulting in long-term contract awards by our customers, especially for projects in the three traditional deepwater basins, and represents a significant portion of our revenue backlog that currently extends into 2016.  Although we believe the deepwater segment has experienced a period of long-term global expansion that could continue for several years, the onset of the global financial crisis in 2008 has caused some of our clients to postpone deepwater exploration and development plans, reducing the urgency to contract deepwater rigs in the near-term. Many customers are reassessing offshore exploration plans and re-evaluating a number of planned deepwater development projects in reaction to a period of increased global economic uncertainty.  Certain customers have excess rig capacity and are attempting to sublease this capacity to other customers.  Some deepwater capacity became available during the second half of 2009 as a result of operators’ reluctance to contract rigs in the near-term and an increased sensitivity to the cost of rig services in an uncertain oil price environment, leading to a decline in dayrates. The lower utilization and dayrate decline is most pronounced among the conventionally moored deepwater semisubmersibles, which generally have the ability to operate in water depths of 4,000 to 6,000 feet and employ less sophisticated features. Dayrates for rigs of this technical specification have weakened and are expected to experience further weakness during 2010 as a growing number of rigs complete contracts ahead of an expected acceleration in customer spending.

Although clients have shown a preference toward rigs with advanced capabilities, including dynamic positioning and parallel well construction and field development features, dayrates for these advanced deepwater rigs could experience declines from levels seen in 2009 should clients continue to delay the commencement of large development programs to later years at a time when deepwater capacity is increasing, particularly in 2010 and 2011 when as many as 22 uncommitted deepwater rigs are expected to complete construction programs and enter the active fleet. Also, customers could engage in further subleasing activity, which would intensify the level of competition for deepwater drilling opportunities, leading to further pricing pressure. A strengthening dayrate environment for advanced deepwater rigs is expected to emerge beyond 2011 or 2012, supported by improving global economic activity which should lead to sound crude oil fundamentals, the commencement of new multi-year field development programs, continued successful exploration results and the global expansion of deepwater drilling programs.

Our midwater fleet currently operates offshore Africa and Brazil, and we expect this geographic presence to remain unchanged through 2010. We currently have 67% of our available rig days for our midwater fleet contracted in 2010, 65% in 2011, 35% in 2012 and 14% in 2013. Customer needs for midwater rigs declined in 2009, resulting in periods of inactivity for some rigs. Subleasing of rigs by clients increased due to the uncertain economic climate, increased difficulty with accessing capital resources and a desire by many clients to reduce capital expenditures to a level which approximated projected cash flows in the year.   Midwater rig availability steadily increased in 2009, with 23 rigs idle worldwide at December 31, 2009, including our semisubmersible Pride South Seas, compared to nine rigs at December 31, 2008, leading to a more challenging dayrate environment. The deteriorating midwater segment fundamentals are due in part to the developing weakness in the deepwater rig segment for conventionally moored deepwater rigs, in which these more capable rigs are forced to bid reduced dayrates on work programs in shallower water depths in an attempt to remain active, thereby eliminating a contract opportunity that may have otherwise been available to a midwater unit.  Also, many of the industry’s midwater rigs are utilized in mature offshore regions that are sensitive to crude oil price volatility, such as the U.K. North Sea. Although four rigs are currently idle in the U.K. North Sea, these units are not expected to migrate to other regions to secure work due to the high cost of returning to the North Sea at some future point.  Finally, the number of midwater rigs located in the U.S. Gulf of Mexico has declined significantly from 12 rigs in 2006 to three rigs at December 31, 2009, due primarily to the risk of mooring system failures during hurricane season, marginal geologic prospects and more attractive opportunities in other regions, such as Brazil. Contract opportunities for midwater rigs with availability over the next 12 months currently remain limited, with most contract opportunities characterized by short durations of six months or less. This more challenging environment is expected to lead to an increasing risk of additional idle capacity, as contracts are expected to conclude on approximately 21% of the industry’s midwater rigs, leading to further deterioration in utilization and dayrates. We expect this outlook to persist until our customers gain further confidence in improving near-term global crude oil fundamentals, resulting in increased predictability regarding crude oil prices.

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       Our independent leg jackup rig fleet currently operates in the Middle East, Asia Pacific and West Africa. We currently have 26% of our available rig days for our independent leg jackup fleet contracted in 2010, 7% in 2011, and no available rig days contracted beyond 2011. The addition of new jackup rig capacity in the industry represents a long-term threat to the segment.  Since 2007, 67 jackup rigs have been added to the global fleet, with another 57 expected to be added by the end of 2012. At present, 48 of the 57 expected new build jackups deliveries have failed to obtain an initial contract award following the completion of construction and are idle in various shipyards in the Far East. The majority of rigs being delivered in 2010 and beyond are without contracts.  Customer demand for jackup rigs declined steadily in 2009 while contract backlogs fell throughout the industry’s existing fleet of rigs and incremental capacity surged. As of December 31, 2009, 129 rigs were idle in the worldwide fleet, representing segment utilization of 72%, compared to 61 rigs idle at December 31, 2008. Dayrates for standard international-class jackup rigs peaked during 2007 and fell throughout 2008 and 2009 as the utilization rate declined to current levels. Although client inquiries and tenders have improved somewhat during late 2009 and into 2010, we expect jackup utilization and dayrates to trend lower in the near to intermediate term as existing jackup rigs complete contracts and new capacity is added to the global supply at a time when customers in the Middle East, West Africa and Asia continue to reassess offshore drilling programs. Aggregate jackup rig needs in Mexico were expected to increase during 2009 as Petroleos Mexicanos (“PEMEX”) launched new offshore drilling programs, but these potential needs have been postponed indefinitely, resulting in a number of rigs going idle in the region.

We experienced approximately 660 out-of-service days for shipyard maintenance and upgrade projects for the year ended December 31, 2009, for our existing fleet as compared to approximately 560 days for the year ended December 31, 2008.

Backlog

Our backlog at December 31, 2009, totaled approximately $6.9 billion for our executed contracts, with $2.7 billion attributable to our deepwater drillships under construction. We expect approximately $1.4 billion of our total backlog to be realized in 2010. Our backlog at December 31, 2008 was approximately $8.6 billion. We calculate our backlog, or future contracted revenue for our offshore fleet, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation, customer reimbursables and performance bonuses. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the amount disclosed or expected due to various factors. Downtime due to various operating factors, including unscheduled repairs, maintenance, weather and other factors, may result in lower applicable dayrates than the full contractual operating dayrate, as well as the ability of our customers to terminate contracts under certain circumstances.

The following table reflects the percentage of rig days committed by year as of December 31, 2009. The percentage of rig days committed is calculated as the ratio of total days committed under firm contracts, as well as scheduled shipyard, survey and mobilization days, to total available days in the period. Total available days have been calculated based on the expected delivery dates for our four deepwater rigs under construction.

	For the Years Ending December 31,
	2010	2011	2012	2013
Rig Days Committed
Deepwater	100%	80%	67%	55%
Midwater	67%	65%	35%	14%
Independent Leg Jackups	26%	7%	0%	0%

Critical Accounting Estimates

The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. We base these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur.

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       Our critical accounting estimates are important to the portrayal of both our financial condition and results of operations and require us to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. We would report different amounts in our consolidated financial statements, which could be material, if we used different assumptions or estimates. We have discussed the development and selection of our critical accounting estimates with the Audit Committee of our Board of Directors and the Audit Committee has reviewed the disclosure presented below. During the past three fiscal years, we have not made any material changes in accounting methodology used to establish the critical accounting estimates for property and equipment, income taxes and contingent liabilities.

We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimation.

Property and Equipment

Property and equipment comprise a significant amount of our total assets. We determine the carrying value of these assets based on property and equipment policies that incorporate our estimates, assumptions and judgments relative to the carrying value, remaining useful lives and salvage value of our rigs.

We depreciate our property and equipment over the estimated useful lives using the straight-line method. The assumptions and judgments we use in determining the estimated useful lives of our rigs reflect both historical experience and expectations regarding future operations, utilization and performance. The use of different estimates, assumptions and judgments in the establishment of estimated useful lives, especially those involving our rigs, would likely result in materially different net book values of our property and equipment and results of operations.

Useful lives of rigs and related equipment are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs when certain events occur that directly impact our assessment of the remaining useful lives of the rig and include changes in operating condition, functional capability and market and economic factors. We also consider major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on the future marketability when assessing the useful lives of individual rigs. During 2009 we had no adjustments to the useful lives of the rigs. During 2008, we reviewed the useful lives of certain rigs upon completion of shipyard projects, which resulted in extending the useful lives of the rigs, and as a result reduced depreciation expense by $2.4 million and $0.5 million for continuing and discontinued operations, respectively, and increased after-tax diluted earnings per share from continuing operations by $0.01.  During 2007, we completed a technical evaluation of our offshore fleet. As a result of our evaluation, we increased our estimates of the remaining lives of certain semisubmersible and jackup rigs in our fleet between four and eight years, increased the expected useful lives of our drillships from 25 years to 35 years and our semisubmersibles from 25 years to 30 years, and updated our estimated salvage value for all of our offshore drilling rig fleet to 10% of the historical cost of the rigs. The effect for 2007 of these changes in estimates was a reduction to depreciation expense of approximately $19.3 million and $9.2 million for continuing and discontinued operations, respectively, and an after-tax increase to diluted earnings per share of $0.10 and $0.03 for continuing and discontinued operations, respectively.

We review our property and equipment for impairment whenever events or changes in circumstances indicate the carrying value of such assets or asset groups may not be recoverable. Indicators of possible impairment include (i) extended periods of idle time and/or an inability to contract specific assets or groups of assets, (ii) a significant adverse change in business climate, such as a decline in our market value or fleet utilization, or (iii) an adverse change in the manner or physical condition of a group of assets or a specific asset. However, the drilling industry is highly cyclical and it is not unusual to find that assets that were idle, under-utilized or contracted at sub-economic rates for significant periods of time resume activity at economic rates when market conditions improve. Additionally, our rigs are mobile, and we may mobilize rigs from one market to another to improve utilization or realize higher dayrates. We monitor our recorded asset values every quarter to determine if there has been a triggering event that may result in impairment to any of our assets.  As of December 31, 2009, we determined that we had no triggering event and no impairment to any of our rigs.

We use estimated future undiscounted cash flow analyses to determine whether the carrying values of our assets are recoverable. In general, the analyses are based on expected costs, utilization and dayrates for the estimated remaining useful lives of the asset or group of assets being assessed. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount of the assessed asset or group of assets is not recoverable.

Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets and could materially affect our results of operations.

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Income Taxes

Our income tax expense is based on our income, statutory tax rates and tax planning opportunities available to us in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned. The income tax rates and methods of computing taxable income vary substantially in each jurisdiction. Our income tax expense is expected to fluctuate from year to year as our operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates.

The determination and evaluation of our annual income tax provision involves the interpretation of tax laws in various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events, such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements, treaties, foreign currency exchange restrictions or our levels of operations or profitability in each jurisdiction may impact our tax liability in any given year. While our annual tax provision is based on the information available to us at the time, a number of years may elapse before the ultimate tax liabilities in certain tax jurisdictions are determined.

Current income tax expense reflects an estimate of our income tax liability for the current year, withholding taxes, changes in prior year tax estimates as returns are filed, or from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reflected on the balance sheet. Valuation allowances are determined to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. To determine the amount of deferred tax assets and liabilities, as well as of the valuation allowances, we must make estimates and certain assumptions regarding future taxable income, including where the rigs are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities, or valuation allowances as discussed below.

As of December 31, 2009, we have foreign net operating loss (“NOL”) carryforwards, with respect to all of which we have recognized a valuation allowance. Certain foreign NOL carryforwards do not expire while others could expire starting in 2010 through 2019.

We have not provided for U.S. deferred taxes and related foreign dividend withholding taxes on approximately $1,950.3 million of unremitted earnings of our foreign controlled subsidiaries that are permanently reinvested. If a distribution is made to us from the unremitted earnings of these subsidiaries, we could be required to record additional taxes. It is not practicable to determine the amount of additional taxes that may be assessed upon distribution of unremitted earnings.

As required by law, we file periodic tax returns that are subject to review and examination by various tax authorities within the jurisdictions in which we operate. We are currently contesting several tax assessments and may contest future assessments where we believe the assessments are in error. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments; however, we believe the ultimate resolution of outstanding tax assessments will not have a material adverse effect on our consolidated financial statements.

We do not believe that it is possible to reasonably estimate the potential impact of changes to the assumptions and estimates identified because the resulting change to our tax liability, if any, is dependent on numerous underlying factors that cannot be reasonably estimated. These include, among other things, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have been appropriate; however, past experience is only a guide and the tax resulting from the resolution of current and potential future tax controversies may have a material adverse effect on our consolidated financial statements.

    Contingencies

       We establish reserves for estimated loss contingencies when we believe a loss is probable and the amount of the loss can be reasonably estimated. Our contingent liability reserves relate primarily to litigation, personal injury claims, indemnities and potential income and other tax assessments (see also “Income Taxes” above). Revisions to contingent liability reserves are reflected in income in the period in which different facts or information become known or circumstances change that affect our previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon our assumptions and estimates regarding the probable outcome of the matter and include our costs to defend. In situations where we expect insurance proceeds to offset contingent liabilities, we record a receivable for all probable recoveries up until the net loss is zero. We recognize contingent gains when the contingency is resolved and the gain has been realized. Should the outcome differ from our assumptions and estimates or other events result in a material adjustment to the accrued estimated contingencies, revisions to the estimated contingency amounts would be required and would be recognized in the period the new information becomes known.

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Segment Review

The following table summarizes our revenues and earnings from continuing operations by our reportable segments:

	For the year ended December 31,
	2009			2008			2007
Deepwater revenues:	(In millions)
Revenues excluding reimbursables	$	810.3		$	874.6		$	636.5
Reimbursable revenues		12.8			7.6			7.3
Total Deepwater revenues		823.1			882.2			643.8
Midwater revenues:
Revenues excluding reimbursables		412.9			419.5			329.5
Reimbursable revenues		6.5			6.0			5.0
Total Midwater revenues		419.4			425.5			334.5
Independent Leg Jackup revenues:
Revenues excluding reimbursables		264.0			273.9			220.4
Reimbursable revenues		1.3			1.3			1.4
Total Independent Leg Jackup revenues		265.3			275.2			221.8
Other		83.0			119.2			127.9
Corporate		3.4			0.5			1.0
Total revenues	$	1,594.2		$	1,702.6		$	1,329.0
Earnings (loss) from continuing operations:
Deepwater	$	348.3		$	454.7		$	267.4
Midwater		129.0			163.6			141.4
Independent Leg Jackups		105.4			133.2			92.5
Other		4.8			7.8			59.3
Corporate		(174.2	)		(132.2	)		(142.4	)
Total	$	413.3		$	627.1		$	418.2

The following table summarizes our average daily revenues and utilization percentage by segment:

	2009		2008		2007
	Average Daily Revenues (1)	Utilization (2)	Average Daily Revenues (1)	Utilization (2)	Average Daily Revenues (1)	Utilization (2)
Deepwater	$      335,100	84%	$      310,100	97%	$      230,800	96%
Midwater	$      258,700	74%	$      249,400	78%	$      192,200	79%
Independent Leg Jackups	$      123,000	84%	$      121,100	89%	$      100,600	86%

____________

(1)	Average daily revenues are based on total revenues for each type of rig divided by actual days worked by all rigs of that type. Average daily revenues will differ from average contract dayrate due to billing adjustments for any non-productive time, mobilization fees, demobilization fees, performance bonuses and charges to the customer for ancillary services.
(2)	Utilization is calculated as the total days worked divided by the total days in the period.

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Deepwater

2009 Compared with 2008

Revenues for our deepwater segment decreased $59.1 million, or 7%, for 2009 over 2008. The decrease in revenues is primarily due to decreased utilization of the Pride North America, which experienced approximately 136 out-of-service days as a result of a scheduled five year regulatory inspection and client requested upgrades in 2009. Also, the Pride South Pacific, which was mobilized to Cape Town for a regulatory inspection, experienced 124 out-of-service days during 2009. In addition, the Pride Rio de Janeiro worked at a higher dayrate in 2008 than in 2009. This decrease in revenues was partially offset by increased dayrates for the Pride Angola, Pride Brazil and Pride Carlos Walter, which collectively contributed approximately $68 million in incremental revenues in 2009 than in 2008. As a result of the higher dayrates described above, average daily revenues increased 8% for 2009 over 2008. Earnings from operations for the segment decreased $106.4 million, or 23%, for 2009 over 2008 primarily due to the decline in revenues and an increase in repair and maintenance costs, primarily for the Pride North America, Pride Africa and Pride Portland.  The decrease was also due to an increase in total labor costs for offshore rig crews, primarily for the Pride Angola and Pride Africa. Utilization decreased to 84% for 2009 as compared to 97% for 2008 due to higher out-of-service time related to shipyard projects during 2009.

2008 Compared with 2007

Revenues for our deepwater segment increased $238.4 million, or 37% , for 2008 over 2007 as our deepwater units earned higher dayrates, reflecting the strong worldwide demand for deepwater rigs. The increase in revenues is primarily due to four of our rigs commencing new contracts at higher dayrates, which contributed approximately $180 million of incremental revenues in 2008 over 2007. The strong performance was also due to the increased utilization of the Pride Rio de Janeiro, which had a 21% increase in days worked in 2008 over 2007.  Average daily revenues increased 34% for 2008 over 2007 primarily due to higher dayrates. Earnings from operations increased $187.3 million, or 70%, for 2008 over 2007 due to the increase in revenues and a decrease in depreciation expense from the change in estimate of useful lives effective July 2007. The increase in earnings from operations was partially offset by a 26% increase in overall labor costs for our rig crews, and an increase in repair and maintenance costs. Utilization increased to 97% for 2008 as compared to 96% for 2007.

Midwater

2009 Compared with 2008

Revenues for our midwater segment decreased $6.1 million, or 1%, for 2009 over 2008. The decrease in revenues is primarily due to lower utilization of the Pride Venezuela, which experienced approximately 176 out-of-service days in 2009 following the agreement with the customer to terminate its current contract and the subsequent mobilization of the rig to the shipyard for repairs. This decrease is also due to the Pride South Seas, which completed its contract in August 2009 and was idle the remainder of the year.  This decrease in revenues was largely offset by higher utilization in 2009 of the Pride Mexico, which started operations in July 2008 after the completion of its shipyard project. In addition, there was lower mechanical downtime on the Pride South Atlantic and higher revenues for the Sea Explorer, which commenced a new contract in November 2009 at a substantially higher dayrate. Earnings from operations decreased $34.6 million, or 21%, for 2009 over 2008 due to increased costs related to higher activity for the Pride Mexico, higher rental and transportation costs on the Pride Venezuela,higher depreciation expense from the Pride Mexico and Pride South Seas as a result of their 2008 shipyard projects, and a decline in revenues.  Utilization decreased to 74% for 2009 from 78% for 2008 primarily due to the decreased utilization of the Pride Venezuela and Pride South Seas offset partially by increased utilization for the Pride Mexico and Pride South Atlantic.

2008 Compared with 2007

Revenues for our midwater segment increased $91.0 million, or 27%, in 2008 over 2007 principally due to higher contracted dayrates.  Three rigs, the Pride Mexico, the Sea Explorer and the Pride South Seas, commenced new contracts in 2008 at substantially higher dayrates than their previously contracted rates; these new contracts contributed approximately $85 million in incremental revenue for 2008 over 2007. Partially offsetting the revenue increase was the loss of revenue resulting from out-of-service time for the Pride Venezuela and Pride South Atlantic in 2008 for unplanned repairs. Average daily revenues for 2008 increased 30% over 2007 due to higher dayrates. Earnings from operations increased $22.2 million, or 16%, for 2008 over 2007 due to increased revenues offset partially by lost revenue days from planned shipyard projects coupled with repair and maintenance expenses for the Pride Venezuela and unscheduled maintenance for the Pride South Atlantic in 2008. Utilization decreased to 78% for 2008 from 79% for 2007. The decline in utilization is primarily attributable to unscheduled maintenance and downtime in 2008.

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Independent Leg Jackups

2009 Compared with 2008

Revenues for our independent leg jackup segment decreased $9.9 million, or 4%, for 2009 over 2008. The decrease in revenues is primarily due to the decreased dayrate and lower utilization of the Pride Tennessee, which was stacked in the third quarter of 2009,and lower utilization for the Pride Wisconsin, which was stacked in September 2009. In addition, the Pride Pennsylvania was stacked in the fourth quarter of 2009.  The decrease in revenues was partially offset by a full quarter of higher dayrate on the Pride Montana and higher utilization of the Pride Cabinda following completion of a 192 day shipyard project in 2008. Together, these five rigs contributed to a reduction of $8.8 million in revenue for 2009 over 2008. Average daily revenues increased 2% for 2009 over 2008 due to higher utilization and dayrates for the Pride Cabinda and the Pride Montana. Earnings from operations decreased $27.8 million, or 21%, for 2009 over 2008 due to increased costs for our rig crews offset partially by increased revenues. Utilization decreased to 84% for 2009 from 89% for 2008, primarily due to decreased utilization of the Pride Tennessee  and the Pride Wisconsin, which was cold stacked during the third quarter of 2009, partially offset by reduced shipyard time for the Pride Cabinda and Pride North Dakota.

2008 Compared with 2007

Revenues for our independent leg jackup segment increased $53.4 million, or 24%, for 2008 over 2007 primarily due to the increased utilization for the Pride Hawaii, Pride Tennessee and Pride Wisconsin coupled with the incremental revenue from the Pride Montana, which commenced a new contract in June 2008 at a dayrate that was substantially higher than its previously contracted rate. Average daily revenues increased 20% for 2008 over 2007 primarily due to higher dayrates for the Pride Cabinda and the Pride Montana. Earnings from operations in 2008 increased $40.7 million, or 44%, over 2007 as a result of increased revenues, partially offset by the loss of revenues from higher downtime for the Pride Pennsylvania and the Pride North Dakota. Utilization increased to 89% for 2008 from 86% for 2007. The increase in utilization is primarily the result of decreased shipyard activity for 2008 over 2007.

Other Operations

2009 Compared with 2008

Other operations include our deepwater drilling operations management contracts and other operating activities.  Management contracts in 2009 include one management contract that ended in the third quarter of 2009 and two contracts that expire in 2011 and 2012 (with early termination permitted in certain cases).  Management contracts in 2008 included two contracts that ended in the third and fourth quarters of 2008.

Revenues from our other operations  decreased $36.2 million, or 30%, for 2009 over 2008 primarily due to the termination of two management contracts in the second half of 2008 and a reduction in reimbursable revenue period-over-period in connection with a labor contract. Earnings from operations decreased $3.0 million, or 38%, for 2009 over 2008 primarily due to the decrease in reimbursable revenues.

2008 Compared with 2007

Revenues from our other operations decreased $8.7 million, or 7%, for 2008 over 2007 primarily due to the suspension of drilling services, and the subsequent termination of our management services contract, on the Kizomba A deepwater rig in the third quarter of 2008. We earned approximately $8.6 million in management fee revenues in 2008 for the Kizomba A. Earnings from operations decreased $51.5 million, or 87%, for 2008 over 2007 primarily due to the gain on the sale of our barge rig, Bintang Kalimantan, in December 2007 coupled with higher labor costs and transportation costs in Mexico in 2008.

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Results of Operations

The discussion below relating to significant line items represents our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items.

The following table presents selected consolidated financial information for our continuing operations:

	For the Year Ended December 31,
	2009			2008			2007
	(In millions)
REVENUES
Revenues excluding reimbursable revenues	$	1,563.5		$	1,664.7		$	1,294.2
Reimbursable revenues		30.7			37.9			34.8
		1,594.2			1,702.6			1,329.0
COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		828.3			766.5			618.6
Reimbursable costs		27.3			34.9			30.8
Depreciation and amortization		159.0			147.3			153.1
General and administrative, excluding depreciation and amortization		110.5			126.7			138.1
Department of Justice and Securities and Exchange Commission fines		56.2			-			-
Loss (gain) on sales of assets, net		(0.4	)		0.1			(29.8	)
		1,180.9			1,075.5			910.8
EARNINGS FROM OPERATIONS		413.3			627.1			418.2
OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		(0.1	)		(20.0	)		(83.1	)
Refinancing charges		-			(2.3	)		-
Interest income		3.0			16.8			14.3
Other income (expense), net		(4.1	)		20.6			(2.7	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		412.1			642.2			346.7
INCOME TAXES		(71.8	)		(133.5	)		(86.9	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX	$	340.3		$	508.7		$	259.8

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Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

RevenuesExcluding Reimbursable Revenues. Revenues excluding reimbursable revenues for 2009 decreased $101.2 million, or 6%, compared with 2008. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for 2009 decreased $7.2 million, or 19%, compared with 2008 primarily due to lower activity in our other operations.

Operating Costs. Operating costs for 2009 increased $61.8million, or 8%, compared with 2008.  The increase was primarily due to approximately $26.1 million in higher labor costs for rig crew personnel, including costs for merit increases, retention programs designed to retain key operations personnel and increased training costs. In addition, there was an increase in repair and maintenance costs of approximately $17.0 million for rigs in our deepwater and midwater fleets, a $9.6 million increase attributable to pre-launch start-up costs incurred for the Deep Ocean Ascension and Deep Ocean Clarion, which are scheduled to be completed in 2010, a $6.2 million increase associated with employee termination costs in 2009 and a $5.7 million increase in transportation costs.  The increase was partially offset by reduced expenses resulting from the termination of two management contracts in the second half of 2008. Operating costs as a percentage of revenues, excluding reimbursables, were 52% and 45% for 2009 compared with 2008.

Reimbursable Costs. Reimbursable costs for 2009 decreased $7.6 million, or 22%, over 2008 primarily due to lower activity in our other operations.

Depreciation and Amortization. Depreciation expense for 2009 increased $11.7 million, or 8%, compared with 2008. This increase relates to capital additions primarily in our midwater and deepwater segments.

General and Administrative. General and administrative expenses for 2009 decreased $16.2 million, or 13%, compared with 2008. The decrease was due to a $7.0 million reduction related to costs incurred in the 2008 period for upgrades to our information technology infrastructure, a reduction of $5.7 million in expenses related to the ongoing investigation described under “—FCPA Investigation” above, and a reduction of $2.8 million in connection with various cost control initiatives.  This decrease was partially offset by an increase in termination costs due to reductions in headcount.

Department of Justice and Securities and Exchange Commission Fines. We have accrued $56.2 million in anticipation of a possible resolution with the DOJ and the SEC of potential liabilities under the FCPA.

Loss (Gain) on Sale of Assets, Net. We had net gain on sale of assets of $0.4 million for 2009 and a net loss on sale of assets of $0.1 million for 2008, primarily related to the sale of scrap equipment.

Interest Expense. Interest expense for 2009 decreased $19.9 million, or 100%, compared with 2008 due to a $33.5 million increase in capitalized interest in 2009 and debt reductions in 2008.  This decrease was partially offset by a net increase of $14.4 million as a result of the incremental interest expense associated with the issuance of our 8 ½% Senior Notes in June 2009.

Interest Income. Interest income for 2009 decreased $13.8 million, or 82%, compared with 2008 due to the decrease in investment income earned as a result of significantly lower investment yields year-over-year. The decrease was also the result of maintaining lower average cash balances due to the payments made for newbuild drillship construction projects, as compared to 2008.

Other Income (Expense), Net. Other income, net for 2009 decreased $24.7 million, or 120%, compared with 2008 primarily due to an $11.4 million gain recorded in the first quarter of 2008 resulting from the sale of our 30% minority interest in a joint venture that operated several land rigs in Oman. In addition, we had a $10.2 million foreign exchange gain for 2008 as compared to a $5.5 million foreign exchange loss for 2009.

Income Taxes. Our consolidated effective income tax rate for continuing operations for 2009 was 17.4% compared with 20.8% for 2008. The lower tax rate for 2009 was principally the result of an increased proportion of income earned in lower-taxed jurisdictions, tax benefits recognized from the resolution of uncertain tax positions, and tax benefits related to the finalization of certain tax returns, partially offset by non-deductible fines and penalties.

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Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Revenues Excluding Reimbursable Revenues. Revenues excluding reimbursable revenues for 2008 increased $370.5 million, or 29%, compared with 2007. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for 2008 increased $3.1 million, or 9%, over 2007 primarily due to higher activity in our other operations.

Operating Costs. Operating costs for 2008 increased $147.9 million, or 24%, compared with 2007 primarily due to approximately $82.8 million in higher labor costs for rig crew personnel, including costs for merit increases, retention programs designed to retain key operations personnel and increased training costs. In addition, there was an increase of approximately $48.3 million in repair and maintenance costs for rigs in our deepwater and midwater fleet and a $10.5 million increase in transportation costs. Operating costs as a percentage of revenues were 45% and 47% for 2008 and 2007, respectively.

Reimbursable Costs. Reimbursable costs for 2008  increased $4.1 million, or 13%, over 2007 primarily due to higher activity in our other operations.

Depreciation and Amortization. Depreciation expense for 2008 decreased $5.8 million, or 4%, compared with 2007. This decrease is primarily the result of the change in useful life estimates for several of our rigs (see “Critical Accounting Estimates – Property and Equipment” above), partially offset by the completion of a number of capitalized shipyard projects in 2008.

General and Administrative. General and administrative expenses for 2008 decreased $11.4 million, or 8%, compared with 2007, primarily due to a decrease of $17.3 million of expenses related to the ongoing investigation described under “— FCPA Investigation” above, partially offset by a $1.4 million increase in the amount expensed in 2008 for upgrades to our information technology infrastructure and an increase of $1.2 million due to higher corporate facility expenses.  The remainder of the increase is due to increased wages and benefits costs.

Loss (Gain) on Sale of Assets, Net. We had net loss on sale of assets of $0.1 million for 2008, primarily related to the sale of scrap equipment. We had net gain on sale of assets of $29.8 million for 2007, primarily due to the sale of one land rig and one barge rig.

Interest Expense. Interest expense for 2008 decreased $63.1 million, or 76%, compared with 2007 primarily due to a $30.0 million increase in capitalized interest and a reduction in interest expense on lower total debt balances resulting from repayment of our 3 1/4% Convertible Senior Notes Due 2033 in May 2008 and our drillship loan facility in March 2008.

Refinancing Charges. Refinancing charges for 2008 were $2.3 million and included $1.2 million for the write-off of unamortized debt issuance costs in March 2008 in conjunction with our drillship loan facility repayment and $1.1 million for the write-off of unamortized debt issuance costs in December 2008 upon retirement of our senior secured credit facility. There were no refinancing charges in 2007.

Interest Income. Interest income for 2008 increased $2.5 million compared with 2007 as a result of maintaining higher cash balances in 2008.

Other Income (Expense), Net. Other income, net for 2008 increased $23.3 million compared with 2007 primarily due to an $11.4 million gain recorded in the first quarter of 2008 resulting from the sale of our 30% minority interest in a joint venture that operated several land rigs in Oman. In addition, we had a $10.2 million foreign exchange gain in 2008 as compared to a $2.9 million foreign exchange loss for 2007.  Partially offsetting these increases was a $0.8 million decrease in 2008 in equity earnings from unconsolidated subsidiaries.

Income Taxes. Our consolidated effective income tax rate for continuing operations for 2008 was 20.8% compared with 25.1% for 2007. The lower tax rate for 2008 was principally the result of increased income in lower-taxed jurisdictions partially offset by the recognition of benefits derived from previously unrecognized tax credits in 2007.

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Liquidity and Capital Resources

Our objective in financing our business is to maintain both adequate financial resources and access to additional liquidity. Our $320 million senior unsecured revolving credit facility provides back-up liquidity to meet our on-going working capital needs. At December 31, 2009, we had $320 million of availability under this facility.

During 2009, we used cash on hand and cash flows generated from operations as our primary source of liquidity for funding our working capital needs, debt repayment and capital expenditures.  In addition, on June 2, 2009 we issued $500 million aggregate principal amount of 8 ½% senior notes due 2019.  We are using the net proceeds from this offering for general corporate purposes.  We believe that our cash on hand, including the net proceeds from the notes offering, cash flows from operations and availability under our revolving credit facility will provide sufficient liquidity through 2010 to fund our working capital needs, scheduled debt repayments and anticipated capital expenditures, including progress payments for our four drillship construction projects. In addition, we will continue to pursue opportunities to expand or upgrade our fleet, which could result in additional capital investment. We may also in the future elect to return capital to our stockholders by share repurchases or the payment of dividends.

We may review from time to time possible expansion and acquisition opportunities relating to our business, which may include the construction or acquisition of rigs or acquisitions of other businesses in addition to those described in this annual report. Any determination to construct or acquire additional rigs for our fleet will be based on market conditions and opportunities existing at the time, including the availability of long-term contracts with attractive dayrates and the relative costs of building or acquiring new rigs with advanced capabilities compared with the costs of retrofitting or converting existing rigs to provide similar capabilities. The timing, size or success of any additional acquisition or construction effort and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to us at that time due to a variety of events, including, among others, credit rating agency downgrades of our debt, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry. In addition, we also review from time to time the possible disposition of assets that we do not consider core to our strategic long-term business plan.

On August 24, 2009 we completed the spin-off of Seahawk to our stockholders through a pro rata stock distribution.  In connection with the spin-off, we made a cash contribution to Seahawk of approximately $47.3 million to achieve a targeted working capital for Seahawk as of May 31, 2009 of $85 million.  We and Seahawk also agreed to indemnify each other for certain liabilities that may arise or be incurred in the future attributable to our respective businesses.  In addition, pursuant to a tax support agreement between us and Seahawk, we have agreed to guarantee or indemnify the issuer of any surety bonds or other collateral issued for Seahawk’s account in respect of certain Mexican tax assessments made prior to the spin-off date.  For additional information about the spin-off, please read “—Recent Developments—Spin-off of Mat-Supported Jackup Business” and “—Loss of Pride Wyoming” above and Note 13 of the Notes to Consolidated Financial Statements in Item 8 of this annual report.

We anticipate making cash payments in 2010 of approximately $56.2 million in connection with a possible resolution with the DOJ and the SEC of potential liability under the FCPA.  There can be no assurance that our discussions with the DOJ and SEC will result in a final settlement of any or all of these issues or, if a settlement is reached, the timing of any such settlement or that the terms of any such settlement would not have a material adverse effect on us.  For additional information regarding the related accrual in 2009 and our FCPA investigation, please read "—FCPA Investigation."

Sources and Uses of Cash — 2009 Compared with 2008

Cash flows provided by operating activities

Cash flows from operations were $627.1 million for 2009 compared with $844.1 million for 2008. The decrease of $217.0 million in cash flows from operations was primarily due to the reduction in cash flow from our discontinued operations. The decline was also due to decreased income from continuing operations, which was primarily the result of lower fleet utilization and higher operating costs, offset partially by a decrease in our trade receivables.

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Cash flows used in investing activities

Cash flows used in investing activities were $1,059.8 million for 2009 compared with $582.5 million for 2008, an increase of $477.3 million.  The increase is primarily attributable to cash proceeds of $376.5 million received on the sale of assets in 2008 compared with $17.0 million in 2009, and a reduction in cash of $82.4 million resulting from the spin-off of Seahawk in 2009.

Purchases of property and equipment totaled $994.4 million and $984.0 million for 2009 and 2008, respectively.  We spent approximately $723.0 million and $637.0 million in 2009 and 2008, respectively, on progress payments, equipment purchases and other capitalized costs in connection with our four deepwater drillship construction projects.

Proceeds from dispositions of property and equipment were $7.4 million for 2009 compared with $65.8 million for 2008.  Included in the proceeds for 2008 was $64.2 million related to the sale of our platform rig fleet.

Cash flows provided by financing activities

Cash flows provided by financing activities were $483.3 million for 2009 compared with cash flows used in financing activities of $439.5 million for the comparable period in 2008, an increase of $922.8 million. The 2009 period included net proceeds of $492.4 million from the June 2009 notes offering, offset partially by $30.3 million of scheduled debt repayments.  In 2008, our net cash used for debt repayments included $300 million to retire all of the outstanding 3¼% Convertible Senior Notes due 2033, $138.9 million to repay in full the outstanding amounts under our drillship loan facility and $30.3 million in scheduled debt repayments. We also received proceeds of $20.1 million and of $24.7 million from employee stock transactions for 2009 and 2008, respectively.

Sources and Uses of Cash — 2008 Compared with 2007

Cash flows provided by operating activities

Cash flows from operations were $844.1 million for 2008 compared with $685.0million for 2007. The increase in cash flows from operations was primarily due to the increase in our income from continuing operations in 2008 due primarily to higher dayrates across the fleet and increased cash flow from our operating accounts.  The increase was partially offset by a decrease in income from discontinued operations.

Cash flows used in investing activities

Cash flows used in investing activities were $582.5 million for 2008 compared with cash flows received from investing activities of $299.1 million for 2007. The decrease in cash flows received from investing activities relates primarily to net decrease in cash provided by asset sales in 2008 as compared to 2007. In 2008, we received $295.7 million in connection with the sale of our three tender-assist rigs and our remaining Eastern Hemisphere land rigs.  In 2007, we received cash proceeds of $947.1 million from the sale of our Latin America Land and E&P Services segments, net of cash disposed of and cash selling costs. The final net proceeds will differ as a result of settlement of the final working capital adjustment, post-closing indemnities, and payment of transaction costs.  In addition, we used approximately $280 million more cash than 2007 for capital spending in connection with our four drillships currently under construction.

Purchases of property and equipment totaled $984.0 million and $656.4 million for 2008 and 2007, respectively. The increase in 2008 is primarily due to progress payments, equipment purchases and other capitalized costs aggregating $637.0 million in connection with the construction of our four deepwater drillship construction projects and the upgrade project for the Pride Mexico.

Proceeds from dispositions of property and equipment were $65.8 million for 2008 compared with $53.4 million for 2007.  Included in the proceeds for 2008 was $64.2 million related to the sale of our platform rig fleet. Included in the proceeds for 2007 was $34.0 million related to the sale of one of our barge rigs and $17.3 million related to the sale of one land rig.

Cash flows used in financing activities

Cash flows used in financing activities were $439.5 million for 2008 compared with $157.8 million for the comparable period in 2007. Our net cash used for debt repayments included $300.0 million to retire all of the outstanding 3 1/4% Convertible Senior Notes Due 2033, $138.9 million paid in March 2008 to repay in full the outstanding amounts under our drillship loan facility and $30.3 million in other scheduled debt repayments. We also received net proceeds of $24.7 million and $29.7 million from employee stock transactions in 2008 and 2007, respectively.

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Working Capital

As of December 31, 2009, we had working capital of $661.8 million compared with $849.6 million as of December 31, 2008. The decrease in working capital is primarily due to expenditures incurred towards the construction of our four ultra-deepwater drillships and a reduction in cash due to the spin-off of Seahawk, offset partially by cash received from the June 2009 notes offering and various asset sales in 2009.

Credit Ratings

Our 7 3/8% Senior Notes due 2014 and our 8 1/2% Senior Notes due 2019 are rated BBB- by Standard & Poor’s  Rating Services with a stable outlook, Ba1 by Moody’s Investor Service, Inc. with a positive outlook and BB+ by Fitch Ratings with a stable outlook.

Revolving Credit Facility

In December 2008, we entered into a $300 million unsecured revolving credit agreement with a group of banks maturing in December 2011. In July 2009, borrowing availability under the facility was increased to $320 million.  Borrowings under the credit facility are available to make investments, acquisitions and capital expenditures, to repay and back-up commercial paper and for other general corporate purposes. We may obtain up to $100 million of letters of credit under the facility. The credit facility also has an accordion feature that would, under certain circumstances, allow us to increase the availability under the facility to up to $600 million. Amounts drawn under the credit facility bear interest at variable rates based on LIBOR plus a margin or the alternative base rate. The interest rate margin applicable to LIBOR advances varies based on our credit rating. As of December 31, 2009, there were no outstanding borrowings or letters of credit outstanding under the facility, and our borrowing availability was $320 million.

The credit facility contains a number of covenants restricting, among other things, liens; indebtedness of our subsidiaries; mergers and dispositions of all or substantially all of our or certain of our subsidiaries’ assets; agreements limiting the ability of subsidiaries to make dividends, distributions or other payments to us or other subsidiaries; affiliate transactions; hedging arrangements outside the ordinary course of business; and sale-leaseback transactions. The facility also requires us to maintain certain ratios with respect to earnings to interest expenses and debt to tangible capitalization. The facility contains customary events of default, including with respect to a change of control.

In connection with the closing under our new credit facility, we terminated our then-existing $500 million senior secured credit facility. We incurred no termination penalties and recognized a charge of $1.1 million in 2008 related to the write-off of unamortized debt issuance costs in connection with the termination.

Other Outstanding Debt

As of December 31, 2009, in addition to our credit facility, we had the following long-term debt, including current maturities, outstanding:

• $500 million principal amount of 8 1/2% Senior Notes due 2019;

• $500 million principal amount of 7 3/8% Senior Notes due 2014; and

• $197 million principal amount of notes guaranteed by the United States Maritime Administration.

Our 8 1/2% Senior Notes and our 7 3/8% Senior Notes contain provisions that limit our ability and the ability of our subsidiaries, with certain exceptions, to engage in sale and leaseback transactions, create liens and consolidate, merge or transfer all or substantially all of our assets. We are required to offer to repurchase the 7 3/8% Senior Notes in connection with specified change in control events that result in a ratings decline. If we are required to make such an offer to repurchase our 7 3/8% Senior Notes, we will be required to make a concurrent offer to purchase the 8 1/2% Senior Notes.

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Our notes guaranteed by the United States Maritime Administration were used to finance a portion of the cost of construction of the Pride Portland and Pride Rio de Janeiro. The notes bear interest at a weighted average fixed rate of 4.33% with semi-annual principal payments until maturity in 2016 and are prepayable, in whole or in part, at any time, subject to a make-whole premium. The notes are collateralized by the two rigs and the net proceeds received by subsidiary project companies chartering the rigs.

In April 2008, we called for redemption all of the outstanding 3 1/4% Convertible Senior Notes Due 2033 in accordance with the terms of the indenture governing the notes. The redemption price was 100% of the principal amount thereof, plus accrued and unpaid interest (including contingent interest) to the redemption date. Holders of the notes could elect to convert the notes into our common stock at a rate of 38.9045 shares of common stock per $1,000 principal amount of the notes, at any time prior to the redemption date. Holders of the notes elected to convert a total of $299.7 million aggregate principal amount of the notes, and the remaining $254,000 aggregate principal amount was redeemed by us on the redemption date. We delivered an aggregate of approximately $300.0 million in cash and approximately 5.0 million shares of common stock in connection with the retirement of the notes.

Although we do not expect that our level of total indebtedness will have a material adverse impact on our financial position, results of operations or liquidity in future periods, it may limit our flexibility in certain areas. Please read “Risk Factors — Our significant debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities” in Item 1A of this annual report.

Other Sources and Uses of Cash

We expect our purchases of property and equipment for 2010, excluding our new drillship commitments, to be approximately $200 million for refurbishment and upgrade of our rigs and $30 million for critical spares and other ancillary projects. These purchases are expected to be used primarily for various rig upgrades in connection with new contracts as contracts expire during the year along with other sustaining capital projects. With respect to our four deepwater drillships currently under construction, the total remaining costs are estimated to be approximately $1.4 billion, of which approximately $1.1 billion is committed at December 31, 2009. We anticipate making additional payments for the construction of these drillships of approximately $680 million in 2010 and approximately $735 million in 2011.  We expect to fund construction of these rigs through available cash, cash flow from operations and borrowings under our revolving credit facility.

We anticipate making income tax payments of approximately $45 million to $55 million in 2010.

Mobilization fees received from customers and the costs incurred to mobilize a rig from one geographic area to another, as well as up-front fees to modify a rig to meet a customer’s specifications, are deferred and amortized over the term of the related drilling contracts. These up-front fees and costs impact liquidity in the period in which the fees are received or the costs incurred, whereas they will impact our statement of operations in the periods during which the deferred revenues and costs are amortized. The amount of up-front fees received and the related costs vary from period to period depending upon the nature of new contracts entered into and market conditions then prevailing. Generally, contracts for drilling services in remote locations or contracts that require specialized equipment will provide for higher up-front fees than contracts for readily available equipment in major markets.

We may redeploy additional assets to more active regions if we have the opportunity to do so on attractive terms. We frequently bid for or negotiate with customers regarding multi-year contracts that could require significant capital expenditures and mobilization costs. We expect to fund project opportunities primarily through a combination of working capital, cash flow from operations and borrowings under our revolving credit facility.

In addition to the matters described in this “— Liquidity and Capital Resources” section, please read “— Our Business” and “— Segment Review” for additional matters that may have a material impact on our liquidity.

Letters of Credit

We are contingently liable as of December 31, 2009 in the aggregate amount of $377.6 million under certain performance, bid and custom bonds and letters of credit. As of December 31, 2009, we had not been required to make any collateral deposits with respect to these agreements.

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Contractual Obligations

In the table below, we set forth our contractual obligations as of December 31, 2009. Some of the figures we include in this table are based on our estimates and assumptions about these obligations, including their duration and other factors. The contractual obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

			Less Than						After
	Total		1 Year		1 - 3 Years		4 - 5 Years		5 Years
	(In millions)
Recorded contractual obligations:
Principal payments on long-term debt(1)	$	1,192.0	$	30.3	$	60.6	$	559.2	$	541.9
Trade payables		132.4		132.4		-		-		-
Other long-term liabilities(2)		3.3		3.2		0.1		-		-
	$	1,327.7	$	165.9	$	60.7	$	559.2	$	541.9
Unrecorded contractual obligations:
Interest payments on long-term debt(3)		618.0		87.6		171.2		166.0		193.2
Operating lease obligations(4)		48.0		10.5		14.3		8.8		14.4
Purchase obligations(5)		512.7		472.5		40.2		-		-
Drillship construction agreements(6)		1,133.5		489.7		643.8		-		-
	$	2,312.2	$	1,060.3	$	869.5	$	174.8	$	207.6
Total	$	3,639.9	$	1,226.2	$	930.2	$	734.0	$	749.5

____________

(1)	Amounts represent the expected cash payments for our total long-term debt and do not reflect any unamortized discount.
(2)	Amounts represent other liabilities related to severance and termination benefits.
(3)	Amounts represent the expected cash payments for interest on our long-term debt based on the interest rates in place and amounts outstanding at December 31, 2009.
(4)	We enter into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the leases. Our future operating lease payments would change if we exercised these renewal options and if we entered into additional operating lease agreements.
(5)	Includes approximately $111.3 million in purchase obligations related to drillship construction projects.
(6)	Includes shipyard payments under drillship construction agreements for our four drillship construction projects.

As of December 31, 2009, we have approximately $45.6 million of unrecognized tax benefits, including penalties and interest. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

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Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance on transfers and servicing of financial assets to eliminate the concept of a qualifying special-purpose entity, change the requirements for off balance sheet accounting for financial assets, including limiting the circumstances where off balance sheet treatment for a portion of a financial asset is allowable, and require additional disclosures.  The new guidance amends prior principles to require more disclosure about transfers of financial assets and the continuing exposure, retained by the transferor, to the risks related to transferred financial assets, including securitization transactions. It also enhances information reported to users of financial statements by providing greater transparency about transfers of financial assets and an entity’s continuing involvement in transferred financial assets.  The guidance will be effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009. Early application is not permitted. We adopted the provisions of the guidance effective January 1, 2010 and we do not expect the adoption to have a material impact on our consolidated financial statements.

In June 2009, the FASB issued guidance to revise the approach to determine when a variable interest entity should be consolidated.  The new guidance defines how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The guidance requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements.  The guidance will be effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009. Early application is not permitted. We adopted the provisions of the guidance prospectively effective January 1, 2010 and we do not expect the adoption to have a material impact on our consolidated financial statements.

In 2008 the FASB issued guidance that establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. The guidance clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. In addition, the guidance requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary. This guidance is effective for the fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We adopted the provisions of the guidance on January 1, 2009, with no material impact on our consolidated financial statements.

Guidance issued by the FASB in 2008 and 2009 provides that all business combinations are required to be accounted for at fair value under the acquisition method of accounting, but changes the method of applying the acquisition method from previous principles in a number of ways.  Acquisition costs are no longer considered part of the fair value of an acquisition and will generally be expensed as incurred, non-controlling interests are valued at fair value at the acquisition date, in-process research and development is recorded at fair value as an indefinite-lived intangible asset at the acquisition date, restructuring costs associated with a business combination are generally expensed subsequent to the acquisition date, and changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally will affect income tax expense. Contingent assets acquired and liabilities assumed in a business combination are to be recognized at fair value if fair value can be reasonably estimated during the measurement period. We adopted the provisions of this guidance for any acquisitions made subsequent to January 1, 2009, with no material impact on our consolidated financial statements.

In April 2009, the FASBprovided additional guidance for estimating fair value in accordance with Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures, when the volume and level of activity for the asset or liability have significantly decreased.  This additional guidance re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in ASC Topic 820 and clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability. This guidance also provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly.  The scope of this guidance does not include assets and liabilities measured under quoted prices in active markets.  This guidance is applied prospectively to all fair value measurements where appropriate and will be effective for interim and annual periods ending after June 15, 2009.  We adopted the provisions of this guidance effective April 1, 2009, with no material impact on our consolidated financial statements.

The FASB issued guidance in April 2009 requiring publicly-traded companies, as defined in ASC Topic 270, Interim Reporting, to provide disclosures on the fair value of financial instruments in interim financial statements.  The guidance is effective for interim periods ending after June 15, 2009.  We adopted the new disclosure requirements in our second quarter 2009 financial statements with no material impact on our consolidated financial statements.

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The FASB provided transitional guidance for debt securities in April 2009 to make previous guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. Existing recognition and measurement guidance related to other-than-temporary impairments of equity securities was not amended by this guidance.  This guidance is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the provisions of this guidance effective April 1, 2009, with no material impact on our consolidated financial statements.

ASC Topic 855, Subsequent Events, issued by the FASB in May 2009, establishes (i) the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (ii) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements; and (iii) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. In January 2010 ASC Topic 855 was revised to eliminate the requirement that public companies disclose the date through which subsequent events have been evaluated. This topic is effective for interim or annual financial periods ending after June 15, 2009 with the revision being effective for reports issued after January 15, 2010, and shall be applied prospectively.  We adopted the provisions of this topic effective April 1, 2009, with no material impact on our consolidated financial statements.

In June 2009, the FASB Accounting Standards Codification became the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. After the effective date, the codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the codification became non-authoritative.   The new codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We adopted these provisions in the third quarter of 2009, with no change to our consolidated financial statements other than changes in reference to various authoritative accounting pronouncements in our consolidated financial statements.

In August 2009, the FASB provided updated guidance on the manner in which the fair value of liabilities should be determined. Under the updated guidance, in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of defined valuation techniques. This guidance also clarifies that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. We adopted the provisions of the updated guidance in the fourth quarter of 2009, and it did not have a material impact on our consolidated financial statements.

FORWARD-LOOKING STATEMENTS

This annual report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this annual report that address activities, events or developments that we expect, project, believe or anticipate will or may occur in the future are forward-looking statements. These include such matters as:

• market conditions, expansion and other development trends in the contract drilling industry and the economy in general;

• our ability to enter into new contracts for our rigs, commencement dates for rigs and future utilization rates and contract rates for rigs;

• customer requirements for drilling capacity and customer drilling plans;

• contract backlog and the amounts expected to be realized within one year;

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• future capital expenditures and investments in the construction, acquisition, refurbishment and repair of rigs (including the amount and nature thereof and the timing of completion and delivery thereof);

• future asset sales;

• adequacy of funds for capital expenditures, working capital and debt service requirements;

• future income tax payments and the utilization of net operating loss and foreign tax credit carryforwards;

• business strategies;

• expansion and growth of operations;

• future exposure to currency devaluations or exchange rate fluctuations;

• expected outcomes of legal, tax and administrative proceedings, including our ongoing investigation into improper payments to foreign government officials, and their expected effects on our financial position, results of operations and cash flows;

• future operating results and financial condition; and

• the effectiveness of our disclosure controls and procedures and internal control over financial reporting.

We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. These statements are subject to a number of assumptions, risks and uncertainties, including those described under “— FCPA Investigation” above and in “Risk Factors” in Item 1A of this annual report and the following:

• general economic and business conditions, including conditions in the credit markets;

• prices of crude oil and natural gas and industry expectations about future prices;

• ability to adequately staff our rigs;

• foreign exchange controls and currency fluctuations;

• political stability in the countries in which we operate;

• the business opportunities (or lack thereof) that may be presented to and pursued by us;

• cancellation or renegotiation of our drilling contracts or payment or other delays or defaults by our customers;

• unplanned downtime and repairs on our rigs, particularly due to the age of some of the rigs in our fleet;

• changes in laws and regulations; and

• the validity of the assumptions used in the design of our disclosure controls and procedures.

Most of these factors are beyond our control. We caution you that forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in these statements.

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ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. These risks arise primarily as a result of potential changes in the fair market value of financial instruments that would result from adverse fluctuations in interest rates and foreign currency exchange rates as discussed below. We may enter into derivative financial instrument transactions to manage or reduce market risk, but do not enter into derivative financial instrument transactions for speculative purposes.

Interest Rate Risk.  We are exposed to changes in interest rates through our fixed rate long-term debt. Typically, the fair market value of fixed rate long-term debt will increase as prevailing interest rates decrease and will decrease as prevailing interest rates increase. The fair value of our long-term debt is estimated based on quoted market prices where applicable, or based on the present value of expected cash flows relating to the debt discounted at rates currently available to us for long-term borrowings with similar terms and maturities. The estimated fair value of our long-term debt as of December 31, 2009 and 2008 was $1,307.6 million and $702.5 million, respectively, which was more than its carrying value of $1,192.0 million as of December 31, 2009 and less than its carrying value of $723.2 million as of December 31, 2008. A hypothetical 100 basis point decrease in interest rates relative to market interest rates at December 31, 2009 would increase the fair market value of our long-term debt at December 31, 2009 by approximately $64.4 million.

Foreign Currency Exchange Rate Risk.  We operate in a number of international areas and are involved in transactions denominated in currencies other than the U.S. dollar, which expose us to foreign currency exchange rate risk. We utilize the payment structure of customer contracts to selectively reduce our exposure to exchange rate fluctuations in connection with monetary assets, liabilities and cash flows denominated in certain foreign currencies. We also utilize derivative instruments to hedge forecasted foreign currency denominated transactions. At December 31, 2009 and 2008, we had contracts outstanding to exchange an aggregate $6.0 million and $7.0 million, respectively, U.S. dollars to hedge against the change in value of forecasted payroll transactions and related costs denominated in Euros. If we were to incur a hypothetical 10% adverse change in the exchange rate between the U.S. dollar and the Euro, the net unrealized loss associated with our foreign currency denominated exchange contracts as of December 31, 2009 would be approximately $0.6 million. We do not hold or issue foreign currency forward contracts, option contracts or other derivative financial instruments for speculative purposes.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Pride International, Inc.:

We have audited the accompanying consolidated balance sheets of Pride International, Inc. as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pride International, Inc. as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pride International, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 19, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

(signed) KPMG LLP

Houston, Texas

February 19, 2010

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Pride International, Inc.:

We have audited Pride International, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pride International, Inc.’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 for the year ended December 31, 2009. 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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Pride International, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pride International, Inc. as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated February 19, 2010 expressed an unqualified opinion on those consolidated financial statements.

(signed) KPMG LLP

Houston, Texas

February 19, 2010

53

Pride International, Inc.

Consolidated Balance Sheets

(In millions, except par value)

	December 31,
	2009			2008(1)
				(As Adjusted)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	763.1		$	712.5
Trade receivables, net		256.2			438.8
Deferred income taxes		21.6			90.5
Prepaid expenses and other current assets		123.3			177.4
Assets held for sale		-			1.4
Total current assets		1,164.2			1,420.6
PROPERTY AND EQUIPMENT		6,091.0			6,067.8
Less: accumulated depreciation		1,200.7			1,474.9
Property and equipment, net		4,890.3			4,592.9
INTANGIBLE AND OTHER ASSETS		88.4			55.5
Total assets	$	6,142.9		$	6,069.0
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	30.3		$	30.3
Accounts payable		132.4			137.3
Accrued expenses and other current liabilities		339.7			403.4
Total current liabilities		502.4			571.0
OTHER LONG-TERM LIABILITIES		118.3			146.2
LONG-TERM DEBT, NET OF CURRENT PORTION		1,161.7			692.9
DEFERRED INCOME TAXES		102.7			258.9
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 50.0 shares authorized; none issued		-			-
Common stock, $0.01 par value; 400.0 shares authorized; 175.5 and 173.8 shares issued; 174.6 and 173.1 shares outstanding		1.8			1.7
Paid-in capital		2,058.7			2,002.6
Treasury stock, at cost; 0.9 and 0.7 shares		(16.4	)		(13.3	)
Retained earnings		2,210.8			2,408.2
Accumulated other comprehensive income		2.9			0.8
Total stockholders’ equity		4,257.8			4,400.0
Total liabilities and stockholders’ equity	$	6,142.9		$	6,069.0

(1) Amounts include the retrospective adoption of FSP APB 14-1 (now codified principally in ASC 470) implemented in the first quarter of 2009. See Note 5 to Notes to the Consolidated Financial Statements in Item 8 of this annual report.

The accompanying notes are an integral part of the consolidated financial statements.

54

Pride International, Inc.

Consolidated Statements of Operations

(In millions, except per share amounts)

	Year Ended December 31,
	2009			2008(1)			2007(1)
				(As Adjusted)			(As Adjusted)
REVENUES
Revenues excluding reimbursable revenues	$	1,563.5		$	1,664.7		$	1,294.2
Reimbursable revenues		30.7			37.9			34.8
		1,594.2			1,702.6			1,329.0
COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		828.3			766.5			618.6
Reimbursable costs		27.3			34.9			30.8
Depreciation and amortization		159.0			147.3			153.1
General and administrative, excluding depreciation and amortization		110.5			126.7			138.1
Department of Justice and Securities and Exchange Commission fines		56.2			-			-
Loss (gain) on sales of assets, net		(0.4	)		0.1			(29.8	)
		1,180.9			1,075.5			910.8
EARNINGS FROM OPERATIONS		413.3			627.1			418.2
OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		(0.1	)		(20.0	)		(83.1	)
Refinancing charges		-			(2.3	)		-
Interest income		3.0			16.8			14.3
Other income (expense), net		(4.1	)		20.6			(2.7	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		412.1			642.2			346.7
INCOME TAXES		(71.8	)		(133.5	)		(86.9	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX		340.3			508.7			259.8
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX		(54.5	)		342.4			522.0
NET INCOME		285.8			851.1			781.8
LESS: INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		-			-			(3.5	)
NET INCOME ATTRIBUTABLE TO PRIDE	$	285.8		$	851.1		$	778.3
BASIC EARNINGS PER SHARE:
Income from continuing operations	$	1.93		$	2.95		$	1.54
Income (loss) from discontinued operations		(0.31	)		1.99			3.12
Net income	$	1.62		$	4.94		$	4.66
DILUTED EARNINGS PER SHARE:
Income from continuing operations	$	1.92		$	2.89		$	1.51
Income (loss) from discontinued operations		(0.31	)		1.94			2.90
Net income	$	1.61		$	4.83		$	4.41
SHARES USED IN PER SHARE CALCULATIONS
Basic		173.7			170.6			165.6
Diluted		174.0			175.2			178.1

(1) Amounts include the retrospective adoption of FSP APB 14-1 (now codified principally in ASC 470) implemented in the first quarter of 2009. See Note 5 to Notes to the Consolidated Financial Statements in Item 8 of this annual report.

The accompanying notes are an integral part of the consolidated financial statements.

55

Pride International, Inc.

Consolidated Statements of Stockholders’ Equity

(In millions)

																Accumulated
																Other			Non-			Total
	Common Stock				Paid-in			Treasury Stock					Retained			Comprehensive			Controlling			Stockholders’
	Shares		Amount		Capital (1)			Shares		Amount			Earnings (1)			Income (Loss)			Interest			Equity(1)
					(As Adjusted)								(As Adjusted)									(As Adjusted)
Balance, December 31, 2006		165.7	$	1.7	$	1,817.9			0.5	$	(8.0	)	$	819.0		$	3.3		$	28.3		$	2,662.2
Cumulative adjustment for
adoption of new accounting
standards for convertible debt						31.4								(21.8	)								9.6
Comprehensive income
Net income														778.3						3.5			781.8
Foreign currency translation																	2.6						2.6
Cumulative adjustment for
adoption of new income tax
related accounting standards														(18.4	)								(18.4	)
Cumulative adjustment for
adoption of new defined
benefit pension plan
accounting standards																	1.7						1.7
Total comprehensive income														759.9			4.3			3.5			767.7
Purchase of noncontrolling interest																				(31.8	)		(31.8	)
Exercise of stock options						27.6																	27.6
Tax benefit (deficiency) from
stock-based compensation						7.2																	7.2
Reclassification of restricted stock
awards from liability to equity						5.0																	5.0
Stock-based compensation, net		1.8		-		28.4			0.1		(1.9	)											26.5
Balance, December 31, 2007		167.5		1.7		1,917.5			0.6		(9.9	)		1,557.1			7.6			-			3,474.0
Comprehensive income
Net income														851.1									851.1
Foreign currency translation																	(6.0	)					(6.0	)
Foreign currency hedges, net of tax																	0.2						0.2
Change in defined benefit plan
funded status																	(1.0	)					(1.0	)
Total comprehensive income														851.1			(6.8	)		-			844.3
Exercise of stock options		1.1		-		19.0																	19.0
Tax benefit (deficiency) from
stock-based compensation						7.6																	7.6
Retirement of 3 1/4% Convertible
Notes		5.0		-		31.4																	31.4
Stock-based compensation, net		0.2		-		27.1			0.1		(3.4	)											23.7
Balance, December 31, 2008		173.8		1.7		2,002.6			0.7		(13.3	)		2,408.2			0.8			-			4,400.0
Comprehensive income
Net income														285.8									285.8
Foreign currency translation																	2.4						2.4
Foreign currency hedges, net of tax																	(0.3	)					(0.3	)
Change in defined benefit plan
funded status																							-
Total comprehensive income														285.8			2.1			-			287.9
Exercise of stock options		0.9				18.0																	18.0
Tax benefit (deficiency) from
stock-based compensation						(1.4	)																(1.4	)
Stock-based compensation, net		0.8		0.1		39.5			0.2		(3.1	)											36.5
Spin-off of Seahawk														(483.2	)								(483.2	)
Balance,  December 31, 2009		175.5	$	1.8	$	2,058.7			0.9	$	(16.4	)	$	2,210.8		$	2.9		$	-		$	4,257.8

(1) Amounts include the retrospective adoption of FSP APB 14-1 (now codified principally in ASC 470) implemented in the first quarter of 2009. See Note 5 to Notes to the Consolidated Financial Statements in Item 8 of this annual report.

The accompanying notes are an integral part of the consolidated financial statements.

56

Pride International, Inc.

Consolidated Statements of Cash Flows

(In millions)

	Year Ended December 31,
	2009			2008(1)			2007(1)
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:				(As Adjusted)			(As Adjusted)
Net income	$	285.8		$	851.1		$	778.3
Adjustments to reconcile net income to net cash from operating activities:
Gain on sale of Eastern Hemisphere land rigs		(5.4	)		(6.2	)		-
Gain on sale of tender-assist rigs		-			(121.4	)		-
Gain on sale of Latin America and E&P Services segments		-			(56.8	)		(268.6	)
Gain on sale of equity method investment		-			(11.4	)		-
Depreciation and amortization		196.5			210.8			269.7
Amortization and write-offs of deferred financing costs		2.4			5.2			4.0
Amortization of deferred contract liabilities		(53.8	)		(59.0	)		(57.3	)
Impairment charges		33.4			-			-
Gain on sales of assets, net		(0.4	)		(24.0	)		(31.5	)
Deferred income taxes		(13.2	)		78.1			49.8
Excess tax benefits from stock-based compensation		(1.5	)		(7.7	)		(7.2	)
Stock-based compensation		35.9			24.8			23.0
Other, net		0.9			2.2			16.5
Net effect of changes in operating accounts (See Note 15)		142.8			(26.9	)		(152.0	)
Change in deferred gain on asset sales and retirements		4.9			(12.3	)		-
Increase (decrease) in deferred revenue		13.8			(8.7	)		35.3
Decrease (increase) in deferred expense		(15.0	)		6.3			25.0
NET CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES		627.1			844.1			685.0
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Purchases of property and equipment		(994.4	)		(984.0	)		(656.4	)
Reduction of cash from spin-off of Seahawk		(82.4	)		-			-
Purchase of net assets of acquired entities, including acquisition costs, less cash acquired		-			-			(45.0	)
Proceeds from dispositions of property and equipment		7.4			65.8			53.4
Proceeds from the sale of Eastern Hemisphere land rigs, net		9.6			84.9			-
Proceeds from sale of tender-assist rigs, net		-			210.8			-
Proceeds from sale of equity method investment		-			15.0			-
Proceeds from disposition of Latin America Land and E&P Services segments, net of cash disposed		-			-			947.1
Proceeds from insurance		-			25.0			-
NET CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES		(1,059.8	)		(582.5	)		299.1
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Repayments of borrowings		(30.3	)		(537.2	)		(599.5	)
Proceeds from debt borrowings		498.2			68.0			403.0
Debt finance costs		(6.2	)		(2.7	)		-
Decrease in restricted cash		-			-			1.8
Net proceeds from employee stock transactions		20.1			24.7			29.7
Excess tax benefits from stock-based compensation		1.5			7.7			7.2
NET CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES		483.3			(439.5	)		(157.8	)
Increase (decrease) in cash and cash equivalents		50.6			(177.9	)		826.3
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		712.5			890.4			64.1
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	763.1		$	712.5		$	890.4

(1) Amounts include the retrospective adoption of FSP APB 14-1 (now codified principally in ASC 470) implemented in the first quarter of 2009. See Note 5 to Notes to the Consolidated Financial Statements in Item 8 of this annual report.

The accompanying notes are an integral part of the consolidated financial statements.

57

Pride International, Inc.

Notes to Consolidated Financial Statements

NOTE 1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Pride International, Inc. (“Pride,” “we,” “our,” or “us”) is a leading international provider of offshore contract drilling services. We provide these services to oil and natural gas exploration and production companies through the operation and management of 23 offshore rigs. We also have four ultra-deepwater drillships under construction.

Basis of Presentation

In August 2009, we completed the spin-off of Seahawk Drilling Inc., which holds the assets and liabilities that were associated with our 20-rig mat-supported jackup business.  In early 2008, we completed the sale of our three tender-assist rigs. In the third quarter of 2008, we entered into agreements to sell our Eastern Hemisphere land rig operations and completed the sale of all but one land rig used in those operations in the fourth quarter of 2008. The sale of the remaining land rig closed in the second quarter of 2009.  In August 2007, we completed the sale of our Latin America Land and E&P Services segments. The results of operations for all periods presented of the assets disposed of in all of these transactions have been reclassified to income from discontinued operations. Except where noted, the discussions in the following notes relate to our continuing operations only (see Note 2).

The consolidated financial statements include the accounts of Pride and all entities that we control by ownership of a majority voting interest as well as variable interest entities for which we are the primary beneficiary. All significant intercompany transactions and balances have been eliminated in consolidation. Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. Investments in which we do not exercise significant influence are accounted for using the cost method of accounting.

    Subsequent Events

        In preparing these financial statements, we have evaluated subsequent events through the date the financial statements are being issued, which is February 19, 2010.

Management Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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.

Fair Value Accounting

We use fair value measurements to record fair value adjustments to certain financial and nonfinancial assets and liabilities and to determine fair value disclosures. Our foreign currency forward contracts are recorded at fair value on a recurring basis (see Note 6).

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Depending on the nature of the asset or liability, we use various valuation techniques and assumptions when estimating fair value. For accounting disclosure purposes, a three-level valuation hierarchy of fair value measurements has been established. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date.

When determining the fair value measurements for assets and liabilities required or permitted to be recorded or disclosed at fair value, we consider the principal or most advantageous market in which we would transact and consider assumptions that market participants would use when pricing the asset or liability. When possible, we look to active and observable markets to price identical assets or liabilities. When identical assets and liabilities are not traded in active markets, we look to market observable data for similar assets and liabilities. Nevertheless, certain assets and liabilities are not actively traded in observable markets, and we are required to use alternative valuation techniques to derive an estimated fair value measurement. We adopted new guidance on January 1 and April 1, 2009 with no material impact on our consolidated financial statements.

58

Conditions Affecting Ongoing Operations

Our current business and operations are substantially dependent upon conditions in the oil and natural gas industry and, specifically, the exploration and production expenditures of oil and natural gas companies. The demand for contract drilling and related services is influenced by, among other things, crude oil and natural gas prices, expectations about future prices, the cost of producing and delivering crude oil and natural gas, government regulations and local and international political and economic conditions. There can be no assurance that current levels of exploration and production expenditures of oil and natural gas companies will be maintained or that demand for our services will reflect the level of such activities.

Dollar Amounts

All dollar amounts (except per share amounts) presented in the tabulations within the notes to our financial statements are stated in millions of dollars, unless otherwise indicated.

Revenue Recognition

We recognize revenue as services are performed based upon contracted dayrates and the number of operating days during the period. Revenues are recorded net of value-added taxes or similar type taxes imposed on any revenue-producing transactions.  Mobilization fees received and costs incurred to mobilize a rig from one geographic area to another in connection with a drilling contract are deferred and recognized on a straight-line basis over the term of such contract, excluding any option periods. Costs incurred to mobilize a rig without a contract are expensed as incurred. Lump-sum payments received to reimburse us for capital improvements to rigs are deferred and recognized on a straight-line basis over the period of the related drilling contract. The costs of such capital improvements are capitalized and depreciated over the useful lives of the assets.  Contract dayrate adjustments are recognized when determinable and accepted by the customer.

Cash and Cash Equivalents

We consider all highly liquid debt instruments having maturities of three months or less at the date of purchase to be cash equivalents.

Property and Equipment

Property and equipment are carried at original cost or adjusted net realizable value, as applicable. Major renewals and improvements are capitalized and depreciated over the respective asset’s remaining useful life. Maintenance and repair costs are charged to expense as incurred. When assets are sold or retired, the remaining costs and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in results of operations.

We depreciate property and equipment using the straight-line method based upon expected useful lives of each class of assets. The expected original useful lives of the assets for financial reporting purposes range from five to 35 years for rigs and rig equipment and three to 20 for other property and equipment. We evaluate our estimates of remaining useful lives and salvage value for our rigs when changes in market or economic conditions occur that may impact our estimates of the carrying value of these assets and when certain events occur that directly impact our assessment of the remaining useful lives of the rig and include changes in operating condition, functional capability, market and economic factors. In conducting this evaluation, the scope of work, age of the rig, general condition of the rig and design of the rig are factors that are considered in the evaluation. We also consider major capital upgrades required or rig refurbishment to perform certain contracts and the long-term impact of those upgrades on the future marketability when assessing the useful lives of individual rigs. During 2008, we reviewed the useful lives of certain rigs upon completion of shipyard projects, which resulted in extending the useful lives of the rigs, and as a result reduced depreciation expense by $2.4 million and $0.5 million for continuing and discontinued operations, respectively, and increased after-tax diluted earnings per share from continuing operations by $0.01.  During 2007, we completed a technical evaluation of our offshore fleet. As a result of our evaluation, we increased our estimates of the remaining lives of certain semisubmersible and jackup rigs in our fleet between four and eight years, increased the expected useful lives of our drillships from 25 years to 35 years and our semisubmersibles from 25 years to 30 years, and updated our estimated salvage value for all of our offshore drilling rig fleet to 10% of the historical cost of the rigs. The effect for 2007 of these changes in estimates was a reduction to depreciation expense of approximately $19.3 million and $9.2 million for continuing and discontinued operations, respectively, and an after-tax increase to diluted earnings per share of $0.10 and $0.03 for continuing and discontinued operations, respectively.

59

Interest is capitalized on construction-in-progress at the weighted average cost of debt outstanding during the period of construction or at the interest rate on debt incurred for construction.

We assess the recoverability of the carrying amount of property and equipment if certain events or changes occur, such as a significant decrease in market value of the assets or a significant change in the business conditions in a particular market. In connection with the spin-off of Seahawk in August 2009, we conducted a fair value assessment of its long-lived assets.  As a result of this assessment, we determined that the carrying value of these assets exceeded the fair value, resulting in an impairment loss of $33.4 million.  We recorded the loss in income from discontinued operations for 2009.  In 2008 and 2007, we recognized no impairment charges.

Rig Certifications

We are required to obtain certifications from various regulatory bodies in order to operate our offshore drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs associated with obtaining and maintaining such certifications, including inspections and surveys, and drydock costs to the rigs are deferred and amortized over the corresponding certification periods.

As of December 31, 2009 and 2008, the deferred and unamortized portion of such costs on our balance sheet was $31.4 million and $22.1 million, respectively. The portion of the costs that are expected to be amortized in the 12 month periods following each balance sheet date are included in other current assets on the balance sheet and the costs expected to be amortized after more than 12 months from each balance sheet date are included in other assets. The costs are amortized on a straight-line basis over the period of validity of the certifications obtained. These certifications are typically for five years, but in some cases are for shorter periods. Accordingly, the remaining useful lives for these deferred costs are up to five years.

Derivative Financial Instruments

We enter into derivative financial transactions to hedge exposures to changing foreign currency exchange rates.  We do not enter into derivative transactions for speculative or trading purposes. As of December 31, 2009 and 2008, we designated our foreign currency derivative financial instruments as cash flow hedges whereby gains and losses on these instruments were recognized in earnings in the same period in which the hedged transactions affected earnings. In 2007, we maintained interest rate swap and cap agreements that were not designated as hedges for accounting purposes. Accordingly, the changes in fair value of those derivative financial instruments are recorded in “Other income, net” in our consolidated statement of operations.

Income Taxes

We recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Deferred tax liabilities and assets are determined based on the difference between the financial statement and the tax basis of assets and liabilities using enacted tax rates in effect for the year in which the asset is recovered or the liability is settled. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Because of tax jurisdictions in which we operate, some of which are revenue based tax regimes, changes in earnings before taxes and minority interest do not directly correlate to changes in our provision for income tax.

Foreign Currency Translation

We have designated the U.S. dollar as the functional currency for most of our operations in international locations because we contract with customers, purchase equipment and finance capital using the U.S. dollar. In those countries where we have designated the U.S. dollar as the functional currency, certain assets and liabilities of foreign operations are translated at historical exchange rates, revenues and expenses in these countries are translated at the average rate of exchange for the period, and all translation gains or losses are reflected in the period’s results of operations. In those countries where the U.S. dollar is not designated as the functional currency, revenues and expenses are translated at the average rate of exchange for the period, assets and liabilities are translated at end of period exchange rates and all translation gains and losses are included in accumulated other comprehensive income (loss) within stockholders’ equity.

60

Concentration of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. We invest our cash and cash equivalents in high quality financial instruments. We limit the amount of credit exposure to any one financial institution or issuer. Our customer base consists primarily of major integrated and government-owned international oil companies, as well as smaller independent oil and gas producers. Management believes the credit quality of our customers is generally high. We provide allowances for potential credit losses when necessary.

Stock-Based Compensation

We recognize compensation expense for awards of equity instruments based on the grant date fair value of those awards.  We recognize these compensation costs net of an estimated forfeiture rate, and recognize compensation cost for only those shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the award vesting term. The risk-free interest rate is based on the implied yield currently available on U.S. Treasury zero coupon issues with a remaining term equal to the expected life. Expected dividend yield is based on historical dividend payments. For the years ended December 31, 2008 and 2007, we estimated the fair value of stock options granted and Employee Stock Purchase Plan (“ESPP”) shares purchased using an implied volatility based on actively traded options on our common stock.  Implied volatility for options granted during 2008 and 2007 was 35.1% and 31.2%, respectively.  On January 2, 2009, we granted approximately 1,189,000 stock options (“2009 Grants”) and determined a grant date fair value using an implied volatility of 68.7%. During 2009, management performed an analysis, by looking at different methodologies for deriving and utilizing implied volatility, historical volatility and a blend of implied and historical volatility, to determine if the exclusive use of implied volatility was the proper method for estimating the expected volatility and future stock price trends. For the year ended December 31, 2009, we changed our methodology for estimating expected volatility from implied volatility calculated based on actively traded options on our common stock to a combination of historical volatility and peer group historical volatility.  In changing our methodology, we considered, among other factors, the volume of our traded options and the expected terms of our employee options. The historical volatility is determined by observing the actual prices of our common stock over a period commensurate with the expected life of the awards weighted appropriately with the effects of  certain changes in business composition or capital structure, including the sale of our Eastern Hemisphere land rigs, the disposition of our Latin America Land and E&P Services segments and other non-core businesses.  The peer group volatility was based on historical volatilityof a comparable peer group consisting of companies of similar size and operating in a similar industry adjusted for differences in capital structure and weighted for periods of significant volatility due to general market conditions.  We believe this approach more closely reflects the factors that marketplace participants would likely use to assess the expected volatility of our awards on the date of grant. We use the “short-cut method” to establish the balance of the additional paid-in capital pool ("APIC pool") related to the tax effects of employee stock-based compensation, and to determine the impact on the APIC pool and the statement of cash flows of the tax effects of employee stock-based compensation awards. As a result of our analysis, and the change in the methodology for estimating our expected volatility, we revised the grant date fair value of the 2009 Grants and the 2009 ESPP purchases using a 31.8% volatility.

Earnings per Share

Basic earnings per share from continuing operations has been computed based on the weighted average number of shares of common stock outstanding during the applicable period. Diluted earnings per share from continuing operations has been computed based on the weighted average number of shares of common stock and common stock equivalents outstanding during the applicable period, as if stock options, restricted stock awards, convertible debentures and other convertible debt were converted into common stock, after giving retroactive effect to the elimination of interest expense, net of income taxes.

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Accounting Pronouncements

       In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance on transfers and servicing of financial assets to eliminate the concept of a qualifying special-purpose entity, change the requirements for off balance sheet accounting for financial assets, including limiting the circumstances where off balance sheet treatment for a portion of a financial asset is allowable, and require additional disclosures.  The new guidance amends prior principles to require more disclosure about transfers of financial assets and the continuing exposure, retained by the transferor, to the risks related to transferred financial assets, including securitization transactions. It also enhances information reported to users of financial statements by providing greater transparency about transfers of financial assets and an entity’s continuing involvement in transferred financial assets.  The guidance will be effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009. Early application is not permitted. We adopted the provisions of the guidance effective January 1, 2010 and we do not expect the adoption to have a material impact on our consolidated financial statements.

In June 2009, the FASB issued guidance to revise the approach to determine when a variable interest entity should be consolidated.  The new guidance defines how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The guidance requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements.  The guidance will be effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009. Early application is not permitted. We adopted the provisions of the guidance prospectively effective January 1, 2010 and we do not expect the adoption to have a material impact on our consolidated financial statements.

In 2008 the FASB issued guidance that establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. The guidance clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. In addition, the guidance requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary. This guidance is effective for the fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We adopted the provisions of the guidance on January 1, 2009, with no material impact on our consolidated financial statements.

Guidance issued by the FASB in 2008 and 2009 provides that all business combinations are required to be accounted for at fair value under the acquisition method of accounting, but changes the method of applying the acquisition method from previous principles in a number of ways.  Acquisition costs are no longer considered part of the fair value of an acquisition and will generally be expensed as incurred, non-controlling interests are valued at fair value at the acquisition date, in-process research and development is recorded at fair value as an indefinite-lived intangible asset at the acquisition date, restructuring costs associated with a business combination are generally expensed subsequent to the acquisition date, and changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally will affect income tax expense. Contingent assets acquired and liabilities assumed in a business combination are to be recognized at fair value if fair value can be reasonably estimated during the measurement period. We adopted the provisions of this guidance for any acquisitions made subsequent to January 1, 2009, with no material impact on our consolidated financial statements.

In April 2009, the FASBprovided additional guidance for estimating fair value in accordance with Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures, when the volume and level of activity for the asset or liability have significantly decreased.  This additional guidance re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in ASC Topic 820 and clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability. This guidance also provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly.  The scope of this guidance does not include assets and liabilities measured under quoted prices in active markets.  This guidance is applied prospectively to all fair value measurements where appropriate and will be effective for interim and annual periods ending after June 15, 2009.  We adopted the provisions of this guidance effective April 1, 2009, with no material impact on our consolidated financial statements.

The FASB issued guidance in April 2009 requiring publicly-traded companies, as defined in ASC Topic 270, Interim Reporting, to provide disclosures on the fair value of financial instruments in interim financial statements.  The guidance is effective for interim periods ending after June 15, 2009.  We adopted the new disclosure requirements in our second quarter 2009 financial statements with no material impact on our consolidated financial statements.

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The FASB provided transitional guidance for debt securities in April 2009 to make previous guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. Existing recognition and measurement guidance related to other-than-temporary impairments of equity securities was not amended by this guidance.  This guidance is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the provisions of this guidance effective April 1, 2009, with no material impact on our consolidated financial statements.

ASC Topic 855, Subsequent Events, issued by the FASB in May 2009, establishes (i) the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (ii) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements; and (iii) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. In January 2010 ASC Topic 855 was revised to eliminate the requirement that public companies disclose the date through which subsequent events have been evaluated. This topic is effective for interim or annual financial periods ending after June 15, 2009 with the revision being effective for reports issued after January 15, 2010, and shall be applied prospectively.  We adopted the provisions of this topic effective April 1, 2009, with no material impact on our consolidated financial statements.

        In June 2009, the FASB Accounting Standards Codification became the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. After the effective date, the codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the codification became non-authoritative.   The new codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We adopted these provisions in the third quarter of 2009, with no change to our consolidated financial statements other than changes in reference to various authoritative accounting pronouncements in our consolidated financial statements.

In August 2009, the FASB provided updated guidance on the manner in which the fair value of liabilities should be determined. Under the updated guidance, in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of defined valuation techniques. This guidance also clarifies that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. We adopted the provisions of the updated guidance in the fourth quarter of 2009, and it did not have a material impact on our consolidated financial statements.

Reclassifications

Certain reclassifications have been made to the prior years’ consolidated financial statements to conform with the current year presentation.

NOTE 2.  DISCONTINUED OPERATIONS

We reclassify, from continuing operations to discontinued operations, for all periods presented, the results of operations for any component either held for sale or disposed of. We define a component as being distinguishable from the rest of our company because it has its own operations and cash flows.  A component may be a reportable segment, an operating segment, a reporting unit, a subsidiary, or an asset group.  Such reclassifications had no effect on our net income or stockholders’ equity.

Spin-off of Mat-Supported Jackup Business

On August 24, 2009, we completed the spin-off of Seahawk, which holds the assets and liabilities that were associated with our mat-supported jackup rig business.  In the spin-off, our stockholders received 100% (approximately 11.6 million shares) of the outstanding common stock of Seahawk by way of a pro rata stock dividend.  Each of our stockholders of record at the close of business on August 14, 2009 received one share of Seahawk common stock for every 15 shares of our common stock held by such stockholder and cash in lieu of any fractional shares of Seahawk common stock to which such stockholder otherwise would have been entitled.

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The following table presents selected information regarding the results of operations of our former mat-supported jackup business:

	2009(1)			2008			2007
Revenues	$	189.4		$	607.9		$	622.5
Operating costs, excluding depreciation and amortization		161.6			326.6			317.2
Depreciation and amortization		37.5			59.2			62.2
General and administrative, excluding depreciation and amortization		34.3			3.9			0.1
Impairment expense		33.4			-			-
Gain on sales of assets, net		(5.0	)		(24.2	)		(0.7	)
Earnings (loss) from operations	$	(72.4	)	$	242.4		$	243.7
Other income (expense), net		2.6			(2.5	)		0.1
Income (loss) before taxes		(69.8	)		239.9			243.8
Income taxes		17.1			(83.2	)		(82.3	)
Income (loss) from discontinued operations	$	(52.7	)	$	156.7		$	161.5

(1) Includes results of operations through August 24, 2009 (the effective date of the spin-off).

In connection with the spin-off, we made a cash contribution to Seahawk of approximately $47.3 million to achieve a targeted working capital for Seahawk as of May 31, 2009 of $85 million. We and Seahawk also agreed to indemnify each other for certain liabilities that may arise or be incurred in the future attributable to our respective businesses.

As of the date of the spin-off, we conducted a fair value assessment of the long-lived assets of Seahawk to determine whether an impairment loss should be recognized. We used multiple valuation methods and weighted the results of those methods for the final fair value determination. For the first valuation technique, we applied the income approach using a discounted cash flows methodology. Our valuation was based upon unobservable inputs that required us to make assumptions about the future performance of the mat-supported jackup rigs for which there is little or no market data, including projected demand, dayrates and operating costs. We also used a recent third-party valuation and recent analyst research reports for our second and third valuation methods. As a result of our fair value assessment, we determined that the carrying value of $521.0 million of the Seahawk long-lived assets exceeded their fair value of $487.6 million, resulting in an impairment loss of $33.4 million. We recorded the loss in income from discontinued operations for the year ended December 31, 2009.

Sale of Eastern Hemisphere Land Rigs

In the third quarter of 2008, we entered into agreements to sell our remaining seven land rigs for $95 million in cash. The sale of all but one rig closed in the fourth quarter of 2008. We leased the remaining rig to the buyer until the sale of that rig closed, which occurred in the second quarter of 2009.  We recognized an after-tax gain of $5.2 million upon closing the sale of the last rig.  Accordingly, this gain, the recognition of which had been previously deferred, was reflected in our income from discontinued operations for the year ended December 31, 2009.

The following table presents selected information regarding the results of operations of this operating group:

	2009			2008			2007
Revenues	$	6.7		$	70.4		$	92.3
Income (loss) before taxes		(1.0	)		8.6			15.4
Income taxes		(2.0	)		(11.1	)		(7.4	)
Gain on disposal of assets, net of tax		5.4			6.2			-
Income (loss) from discontinued operations	$	2.4		$	3.7		$	8.0

Other Divestitures

In February 2008, we completed the sale of our fleet of three self-erecting, tender-assist rigs for $213 million in cash. We operated one of the rigs until mid-April 2009, when we transitioned the operations of that rig to the owner.

During the third quarter of 2007, we completed the disposition of our Latin America Land and E&P Services segments for $1.0 billion in cash. The purchase price was subject to certain post-closing adjustments for working capital and other indemnities. From the closing date of the sale through December 31, 2009, we recorded a total gain on disposal of $325.4 million, which included certain estimates for the settlement of closing date working capital, valuation adjustments for tax and other indemnities provided to the buyer and selling costs incurred by us. We have indemnified the buyer for certain obligations that may arise or be incurred in the future by the buyer with respect to the business. We believe it is probable that some of these liabilities will be settled with the buyer in cash. Our total estimated gain on disposal of assets includes a $29.7 million liability based on our fair value estimates for the indemnities. In December 2008, the final amount of working capital payable by the buyer to us was determined in accordance with the purchase agreement to be approximately $44.5 million, plus approximately $5.8 million of accrued interest to December 31, 2009. To date, the buyer has not made the required payment, and we have received no assurance that payment will be made. The buyer has made various tax and other indemnification claims totaling approximately $40.2 million, as compared to our recorded liabilities related to these claims of $30.5 million. We have filed suit against the buyer in the federal district court in the Southern District of New York to collect the amounts due to us, and the buyer has made various counterclaims in the proceeding. We continue to pursue collection of the amounts due to us and resolution of the tax and indemnification claims with the buyer. The expected settlement dates for the remaining tax indemnities vary from within one year to several years. Our final gain may be materially affected by the final resolution of these matters.

The following table presents selected information regarding the results of operations of these other divestitures:

	2009			2008			2007
Revenues	$	15.0		$	88.0		$	716.5
Income (loss) before taxes		0.7			5.8			127.2
Income taxes		(0.2	)		(2.0	)		(43.3	)
Gain (loss) on disposal of assets, net of tax		(4.7	)		178.2			268.6
Income (loss) from discontinued operations	$	(4.2	)	$	182.0		$	352.5

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NOTE 3. ACQUISITIONS

       In August 2007, we acquired the remaining nine percent interest in the joint venture company that manages our Angolan operations from our partner Sonangol, the national oil company of Angola, for $45.0 million in cash, bringing our total ownership interest to 100%. Prior to this acquisition, we owned a 91% interest in the joint venture company and fully consolidated the balance sheet and results of operations of the joint venture company. The principal assets of the joint venture company include the two ultra-deepwater drillships the Pride Africa and Pride Angola, the jackup rig Pride Cabinda and management agreements for the deepwater platform rigs the Kizomba A and Kizomba B.

Due to our purchase of the remaining joint venture company interest at current market price, we allocated the purchase price by increasing the carrying values of the drillships and the jackup rig by $36.7 million and eliminated the remaining minority interest in the joint venture company of $31.8 million. The current operating contracts for the Pride Africa and Pride Angola include fixed dayrates that were below dayrates for similar contracts as of the date of the acquisition. Accordingly, we adjusted these drilling contracts to fair value as of the date of the acquisition, and as a result, we recorded a non-cash deferred liability of $23.4 million. The deferred contract liability will be amortized to revenues over the remaining lives of the contracts of approximately one to four years.

NOTE 4.  PROPERTY AND EQUIPMENT

Property and equipment consisted of the following at December 31:

	2009			2008
				(As Adjusted)
Rigs and rig equipment	$	4,101.4		$	4,873.6
Construction-in-progress - newbuild drillships		1,682.4			965.5
Construction-in-progress - other		222.8			165.7
Other		84.4			63.0
Property and equipment, cost		6,091.0			6,067.8
Accumulated depreciation and amortization		(1,200.7	)		(1,474.9	)
Property and equipment, net	$	4,890.3		$	4,592.9

Depreciation and amortization expense of property and equipment for 2009, 2008 and 2007 was $159.0 million, $147.3 million and $153.1 million, respectively.

During 2009, 2008 and 2007, maintenance and repair costs included in operating costs on the accompanying consolidated statements of operations were $129.1 million, $112.1 million and $63.8 million, respectively.

We capitalize interest applicable to the construction of significant additions to property and equipment. For 2009, 2008 and 2007, we capitalized interest of $74.7 million, $41.2 million and $11.2 million, respectively. For 2009, 2008 and 2007, total interest costs, including amortization of debt issuance costs, were $74.8 million, $61.2 million and $94.3 million, respectively.

Construction-in-progress – Newbuild Drillships

In July 2007, we acquired an ultra-deepwater drillship under construction. We paid the seller $108.5 million in cash and assumed its obligations under the construction contract, including remaining scheduled payments of approximately $540.0 million. The construction contract provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us in the first quarter of 2010. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from the shipyard for delays during certain periods.

During 2007 and 2008, we entered into agreements to construct three additional advanced-capability ultra-deepwater drillships. The agreements contain fixed purchase prices with scheduled delivery in the third quarter of 2010 and the first and fourth quarters of 2011. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages from the shipyard for delays during certain periods.

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       We expect the total project costs for the four drillships, including commissioning and testing, to be approximately $2.9 billion, excluding capitalized interest. As of December 31, 2009, construction-in-progress related to these four drillship construction contracts was $1,559.7 million, excluding $122.7 million of capitalized interest.  As of December 31, 2008, construction-in-progress related to these four drillship construction contracts was $917.6 million, excluding $44.6 million of capitalized interest.

At December 31, 2009, our purchase obligations to the shipyard related to our four newbuild drillship construction projects as of such date are as follows:

	Amount
2010	$	489.7
2011		643.8
2012		-
2013		-
2014		-
Thereafter		-
	$	1,133.5

Sale of assets

        In December 2007, we sold the Bintang Kalimantan, a barge rig,for $34.0 million, resulting in a pre-tax gain of $20.0 million. In the second quarter of 2007, we completed the sale of one land rig for $17.3 million, resulting in a pre-tax gain on the sale of $8.5 million.

NOTE 5.  INDEBTEDNESS

Senior Unsecured Revolving Credit Facility

In December 2008, we entered into an unsecured revolving credit agreement with a group of banks providing for availability of up to $300.0 million, which was increased to $320.0 million in July 2009. The credit facility matures in December 2011. The credit facility has an accordion feature that would, under certain circumstances, allow us to increase the availability under the facility to up to $600.0 million. Amounts drawn under the credit facility bear interest at variable rates based on LIBOR plus a margin or the alternative base rate as defined in the agreement. The interest rate margin applicable to LIBOR advances varies based on our credit rating.

The credit facility contains a number of covenants restricting, among other things, liens; indebtedness of our subsidiaries; mergers and dispositions of all or substantially all of our or certain of our subsidiaries’ assets; agreements limiting the ability of subsidiaries to make dividends, distributions or other payments to us or other subsidiaries; affiliate transactions; amendments or other modifications to the charter, bylaws or similar documents of us and our subsidiaries; hedging arrangements outside the ordinary course of business; and sale-leaseback transactions. The facility also requires us to maintain certain ratios with respect to earnings to interest expenses and debt to tangible capitalization. The facility contains customary events of default, including with respect to a change of control.

Borrowings under the credit facility are available to make investments, acquisitions and capital expenditures, to repay and back-up commercial paper and for other general corporate purposes.  We may obtain up to $100 million of letters of credit under the facility. As of December 31, 2009 and 2008, there were no outstanding borrowings and no letters of credit outstanding under the facility.

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Senior Secured Credit Facility

       In connection with the closing under our new credit facility, we terminated our then-existing $500 million senior secured revolving credit facility. Amounts drawn under the facility bore interest at variable rates based on LIBOR plus a margin or the base rate plus a margin. The interest rate margin varied based on our leverage ratio. The revolving credit facility would have matured in July 2009. In connection with the retirement of the facility, we recognized a charge of $1.1 million related to the write-off of unamortized debt issuance costs, which is included in “Refinancing charges” for the year ended December 31, 2008.

Our indebtedness consisted of the following at December 31:

	2009		2008
Senior unsecured revolving credit facility	$	-	$	-
8 1/2% Senior Notes due 2019, net of unamortized discount of $1.7 million		498.3		-
7 3/8% Senior Notes due 2014, net of unamortized discount of $1.4 million and $1.7 million, respectively		498.6		498.3
MARAD notes, net of unamortized fair value discount of $1.9 million and  $2.4 million, respectively		195.1		224.9
Total debt		1,192.0		723.2
Less: current portion of long-term debt		30.3		30.3
Long-term debt	$	1,161.7	$	692.9

8 1/2 % Senior Notes due 2019

On June 2, 2009, we completed an offering of $500.0 million aggregate principal amount of 8 1/2% Senior Notes due 2019. The notes bear interest at 8.5% per annum, payable semiannually. We are using the proceeds from this offering, net of discount and issuance costs, of $492.4 million for general corporate purposes. The notes contain provisions that limit our ability and the ability of our subsidiaries, with certain exceptions, to engage in sale and leaseback transactions, create liens and consolidate, merge or transfer all or substantially all of our assets. If we are required to make an offer to repurchase our 7 3/8% Senior Notes due 2014 as a result of specified change in control events that result in a ratings decline, we will be required to make a concurrent offer to purchase the notes. The notes are subject to redemption, in whole or in part, at our option at any time at a redemption price equal to the principal amount of the notes redeemed plus a make-whole premium.  We will also pay accrued but unpaid interest to the redemption date.

7 3/8% Senior Notes due 2014

In July 2004, we completed an offering of $500.0 million principal amount of 7 3/8% Senior Notes due 2014. The notes bear interest at 7.375% per annum, payable semiannually. The notes contain provisions that limit our ability and the ability of our subsidiaries, with certain exceptions, to engage in sale and leaseback transactions, create liens and consolidate, merge or transfer all or substantially all of our assets. We are required to offer to repurchase the notes in connection with specified change in control events that result in a ratings decline. The notes are subject to redemption, in whole or in part, at our option, at redemption prices starting at 103.688% of the principal amount redeemed and declining to 100% for redemptions occurring on or after July 15, 2012.

MARAD Notes

In November 2006, we completed the purchase of the remaining 70% interest in the joint venture entity that owns the Pride Portland and the Pride Rio de Janeiro, which resulted in the addition of approximately $284 million of debt, net of fair value discount, to our consolidated balance sheet. Repayment of the notes, which were used to fund a portion of the construction costs of the rigs, is guaranteed by the United States Maritime Administration (“MARAD”). The notes bear interest at a weighted average fixed rate of 4.33%, mature in 2016 and are prepayable, in whole or in part, at any time, subject to a make-whole premium. The notes are collateralized by the two rigs and the net proceeds received by subsidiary project companies chartering the rigs.

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  3 1/4% Convertible Senior Notes Due 2033

In 2003, we issued $300.0 million aggregate principal amount of 3 1/4% Convertible Senior Notes due 2033. The notes paid interest at a rate of 3.25% per annum. In April 2008, we called for redemption all of our outstanding 3 1/4% Convertible Senior Notes Due 2033 in accordance with the terms of the indenture governing the notes. The redemption price was 100% of the principal amount thereof, plus accrued and unpaid interest (including contingentinterest) to the redemption date. Under the indenture, holders of the notes could elect to convert the notes into our common stock at a rate of 38.9045 shares of common stock per $1,000 principal amount of the notes, at any time prior to the redemption date. Holders of the notes elected to convert a total of $299.7 million aggregate principal amount of the notes, and the remaining $254,000 aggregate principal amount was redeemed by us on the redemption date. We delivered an aggregate of approximately $300.0 million in cash and approximately 5.0 million shares of common stock in connection with the retirement of the notes. As a result of the retirement of the notes, we reversed a long-term deferred tax liability of $31.4 million, which was accounted for as an increase to “Paid-in capital.” The reversal related to interest expense imputed on these notes for U.S. federal income tax purposes.

ASC Subtopic 470-20, Debt with Conversion and Other Options, applies to any convertible debt instrument that may be wholly or partially settled in cash and requires the separation of the debt and equity components of cash-settleable convertibles at the date of issuance.  The accounting under ASC Subtopic 470-20, which we adopted January 1, 2009, required retrospective application for all periods presented and therefore must be applied to our $300 million 3.25% convertible senior notes.  We have calculated a theoretical non-cash interest expense based on a similar debt instrument carrying a fixed interest rate but excluding the equity conversion feature and measured at fair value at the time the notes were issued. As a result, under ASC Subtopic 470-20, the debt component determined for these notes was $251.8 million and the debt discount was $48.2 million.  The equity component, recorded as additional paid-in capital, was $31.3 million, which represents the difference between the proceeds from the issuance of the notes and the fair value of the liability, net of a deferred tax benefit of $16.9 million.  The fixed interest rate was then applied to the debt component of the notes in the form of an original issuance discount and amortized over the life of the notes as a non-cash interest charge. This resulted in a non-cash increase of our historical interest expense, net of amounts capitalized, of $1.5 million, $9.2 million and $9.9 million for 2008, 2007 and 2006, respectively. Additionally, we capitalized approximately $4.0 million of the incremental interest expense associated with the amortization of the debt discount. Application of these changes to our consolidated income statement for the year ended December 31, 2008 resulted in the following differences when compared to amounts previously reported:

	2008			2007
Additional pre-tax non-cash interest expense	$	1.5		$	9.2
Additional deferred tax benefit		(0.5	)		(3.2	)
Retroactive change in net income and retained earnings	$	1.0		$	6.0
Change to basic earnings per share	$	-		$	-
Change to diluted earnings per share	$	-		$	-

An adjustment to reduce prior period retained earnings in the amount of $21.8 million was recorded for the year ended December 31, 2007, reflecting the cumulative impact of the adoption of ASC Subtopic 470-20 on our financial statements.  The amortization of the debt discount required under ASC Subtopic 470-20 is a non-cash expense and has no impact on total operating, investing and financing cash flows in the prior periods or future consolidated statements of cash flows.

Drillship Loan Facility

In March 2008, we repaid the outstanding aggregate principal amount of $138.9 million under the drillship loan facility collateralized by the Pride Africa and Pride Angola. In connection with the retirement of the drillship loan facility, we recognized a charge of $1.2 million related to the write-off of unamortized debt issuance costs, which is included in “Refinancing charges” for the year ended December 31, 2008.  We also settled all of the related interest rate swap and cap agreements (see Note 6).

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    Future Maturities

Future maturities of long-term debt were as follows at December 31:

	Amount
2010	$	30.3
2011		30.3
2012		30.3
2013		30.3
2014		528.9
Thereafter		541.9
	$	1,192.0

NOTE 6.  FINANCIAL INSTRUMENTS

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, foreign currency forward contracts and debt. Except as described below, the estimated fair value of such financial instruments at December 31, 2009 and 2008 approximate their carrying value as reflected in our consolidated balance sheets.

The estimated fair value of our debt at December 31, 2009 and 2008 was $1,307.6 million and $702.5 million, respectively, which differs from the carrying amounts of $1,192.0 million and $723.2 million, respectively, included in our consolidated balance sheets. The fair value of our debt has been estimated based on year-end quoted market prices.

Interest Rate Swap and Cap Agreements

Our drillship loan facility required us to maintain interest rate swap and cap agreements, which were all settled as part of the retirement of the loan facility in March 2008. We did not designate any of the interest rate swap and cap agreements as hedging instruments. Accordingly, the changes in fair value of the interest rate swap and cap agreements were recorded in earnings. In 2008, we recognized a charge of $1.7 million for the realized loss on the settlement of the interest rate swap and cap agreements, which is included in “Other income, net.”

Foreign Exchange Risks

Our operations are subject to foreign exchange risks, including the risks of adverse foreign currency fluctuations and devaluations and of restrictions on currency repatriation. We attempt to limit the risks of adverse currency fluctuations and restrictions on currency repatriation by obtaining contracts providing for payment in U.S. dollars or freely convertible foreign currency. To the extent possible, we may seek to limit our exposure to local currencies by matching its acceptance thereof to its expense requirements in such currencies.

Cash Flow Hedging

In September 2008, we initiated a foreign currency hedging program to moderate the change in value of forecasted payroll transactions and related costs denominated in Euros. We are hedging a portion of these payroll and related costs using forward contracts. When the U.S. dollar strengthens against the Euro, the decline in the value of the forward contracts is offset by lower future payroll costs. Conversely, when the U.S. dollar weakens, the increase in value of forward contracts offsets higher future payroll costs. When effective, these transactions should generate cash flows that directly offset the cash flow impact from changes in the value of our forecasted Euro-denominated payroll transactions. The maximum amount of time that we are hedging our exposure to Euro-denominated forecasted payroll costs is six months. The aggregate notional amount of these forward contracts, expressed in U.S. dollars, was $6.0 million and $7.0 million at December 31, 2009 and 2008, respectively.

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       All of our foreign currency forward contracts were accounted for as cash flow hedges. The fair market value of these derivative instruments is included in prepaid expenses and other current assets or accrued expenses and other current liabilities, with the cumulative unrealized gain or loss included in accumulated other comprehensive income in our consolidated balance sheet. The payroll and related costs that are being hedged are included in accrued expenses and other current liabilities in our consolidated balance sheet, with the realized gain or loss associated with the re-valuation of these liabilities from Euros to U.S. dollars included in other income. Amounts recorded in accumulated other comprehensive income associated with the derivative instruments are subsequently reclassed into other income as earnings are affected by the underlying hedged forecasted transactions. The estimated fair market value of our outstanding foreign currency forward contracts resulted in a liability of approximately $0.1 million and an asset of $0.2 million at December 31, 2009 and 2008, respectively. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between derivative contracts and the hedge item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings and recorded to other income (expense). We did not recognize a gain or loss due to hedge ineffectiveness in our consolidated statements of operations for the years ended December 31, 2009 and 2008 related to these derivative instruments.

The balance of the net unrealized gain related to our foreign currency forward contracts in accumulated other comprehensive income is as follows:

	2009			2008
Net unrealized gain at beginning of period	$	0.2		$	-
Activity during period:
Settlement of forward contracts outstanding at beginning of period		(0.2	)		-
Net unrealized gain (loss) on outstanding foreign currency forward contracts		(0.1	)		0.2
Net unrealized gain (loss) at end of period	$	(0.1	)	$	0.2

Fair Value of Financial Instruments

The following table presents the carrying amount and estimated fair value of our financial instruments recognized at fair value on a recurring basis:

	December 31, 2009				December 31, 2008
		Estimated Fair Value Measurements
		Quoted Prices	Significant	Significant
		in	Other	Unobservable
	Carrying	Active Markets	Observable Inputs	Inputs	Carrying	Estimated
	Amount	(Level 1)	(Level 2)	(Level 3)	Amount	Fair Value
Derivative Financial Instruments:
Foreign currency forward contracts	$        (0.1)	$                  -	$                   (0.1)	$                -	$          0.2	$          0.2

The foreign currency forward contracts have been valued using a combined income and market based valuation methodology based on forward exchange curves and credit. These curves are obtained from independent pricing services reflecting broker market quotes. Our cash and cash equivalents, accounts receivable and accounts payable are by their nature short-term. As a result, the carrying value included in the accompanying consolidated balance sheets approximate fair value.

NOTE 7.  INVESTMENTS IN AFFILIATES

As of December 31, 2007, we had a 30% interest in United Gulf Energy Resource Co. SAOC-Sultanate of Oman (“UGER”), which owns 99.9% of National Drilling and Services Co. LLC (“NDSC”), an Omani company. NDSC owns and operates four land drilling rigs. As of December 31, 2007, our investment in UGER was $3.4 million. In February 2008, we sold our interest in UGER for approximately $15 million.

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NOTE 8.  INCOME TAXES

The provision for income taxes on income from continuing operations is comprised of the following for the years ended December 31:

	2009		2008		2007
U.S.:
Current	$	0.6	$	20.4	$	8.5
Deferred		19.0		18.9		1.5
Total U.S.		19.6		39.3		10.0
Foreign:
Current		51.9		93.6		73.4
Deferred		0.3		0.6		3.5
Total foreign		52.2		94.2		76.9
Income taxes	$	71.8	$	133.5	$	86.9

A reconciliation of the differences between our income taxes computed at the U.S. statutory rate and our income taxes from continuing operations before income taxes and minority interest as reported is summarized as follows for the years ended December 31:

	2009						2008						2007
	Amount			Rate (%)			Amount			Rate (%)			Amount			Rate (%)
U.S. statutory rate	$	144.2			35.0		$	224.8			35.0		$	121.3			35.0
Taxes on foreign earnings at greater (lesser) than the U.S. statutory rate		(93.7	)		(22.7	)		(102.9	)		(16.0	)		(38.3	)		(11.1	)
Change in valuation allowance		-			-			-			-			(6.9	)		(2.0	)
Tax benefit from prior year FTC		-			-			-			-			(6.6	)		(1.9	)
Change in unrecognized tax benefits		1.4			0.3			4.2			0.6			5.0			1.5
Nondeductible fines and penalties		19.9			4.8			0.1			-			0.1			-
Other		-			-			7.3			1.2			12.3			3.6
Income taxes	$	71.8			17.4		$	133.5			20.8		$	86.9			25.1

The 2009 effective tax rate is below the U.S. statutory tax rate primarily due to certain profits taxed in low-tax jurisdictions, tax benefits derived from uncertain tax positions previously unrecognized and tax benefits related to the finalization of certain tax returns, partially offset by nondeductible fines and penalties.  The 2008 effective tax rate is below the U.S. statutory tax rate primarily due to certain profits taxed in low-tax jurisdictions. The 2007 tax rate is below the U.S. statutory rate primarily due to certain profits taxed in the low-tax jurisdictions and the recognition of a U.S. foreign tax credit benefit for a prior period.

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       The domestic and foreign components of income from continuing operations before income taxes and minority interest were as follows for the years ended December 31:

	2009		2008		2007
U.S.	$	15.7	$	193.6	$	39.2
Foreign		396.4		448.6		307.5
Income from continuing operations before income taxes and minority interest	$	412.1	$	642.2	$	346.7

The tax effects of temporary differences that give rise to significant portions of the deferred tax liabilities and deferred tax assets were as follows at December 31:

	2009			2008
Deferred tax assets:
Operating loss carryforwards	$	27.2		$	42.2
Tax credit carryforwards		25.8			86.6
Employee stock-based awards and other benefits		35.3			25.8
Other		7.6			9.2
Subtotal		95.9			163.8
Valuation allowance		(27.2	)		(42.2	)
Total		68.7			121.6
Deferred tax liabilities:
Depreciation		148.4			287.3
Other		1.4			2.2
Total		149.8			289.5
Net deferred tax liability(1)	$	81.1		$	167.9

 (1) The change in deferred tax liability of $86.8 between December 31, 2009 and 2008 is different from the 2009 reported deferred tax expense of $19.3 million. The difference is caused primarily by deferred taxes transferred to Seahawk in a tax-free spin-off transaction, deferred taxes recorded on discontinued operations and tax return benefits from exercise of non-qualified stock options.

Applicable U.S. deferred income taxes and related foreign dividend withholding taxes have not been provided on approximately $1,950.3 million of undistributed earnings and profits of our foreign subsidiaries. We consider such earnings to be permanently reinvested outside the United States. It is not practicable to determine the amount of additional taxes that may be assessed upon distribution of unremitted earnings.

As of December 31, 2009, we had deferred tax assets of $27.2 million relating to $93.5 million of foreign net operating loss (“NOL”) carryforwards, $0.3 million of non-expiring Alternative Minimum Tax (“AMT”) credits, and $25.5 million of U.S. foreign tax credits (“FTC”). The NOL carryforwards and tax credits can be used to reduce our income taxes payable in future years. NOL carryforwards include $38.2 million of losses that do not expire and $55.3 million that could expire starting in 2010 through 2019. We have recognized a $27.2 million valuation allowance on all of these foreign NOL carryforwards due to the uncertainty of realizing certain foreign NOL carryforwards. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized. We have not recorded a valuation allowance against our FTC and AMT credit deferred tax assets, since we believe that future profitability will allow us to fully utilize these tax attributes. Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings prior to the expiration of the carryforwards. The foreign tax credits begin to expire in 2017 and the AMT credits do not expire. We could be required to record an additional valuation allowance against certain or all of our remaining deferred tax assets if market conditions deteriorate or future earnings are below current estimates.

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Uncertain Tax Positions

We recognize a benefit for uncertainty in income taxes if we determine that a position is more likely than not of being sustained upon audit, based solely on the technical merits of the position. We recognize the largest amount of tax benefit that is greater than 50 percent likely of being realized upon settlement. We presume that all tax positions will be examined by a taxing authority with full knowledge of all relevant information. We regularly monitor our tax positions and tax liabilities. We reevaluate the technical merits of our tax positions and recognize an uncertain tax benefit, when (i) there is a completion of a tax audit, (ii) there is a change in applicable tax law including a tax case or legislative guidance, or (iii) there is an expiration of the statute of limitations. If a previously recognized uncertain tax benefit no longer meets the requirements for being recognized, then we adjust our tax benefits. Significant judgment is required in accounting for tax reserves. Although we believe that we have adequately provided for liabilities resulting from tax assessments by taxing authorities, positions taken by tax authorities could have a material impact on our effective tax rate in future periods.

  As of December 31, 2009 and 2008, we have approximately $45.6 million and $45.1 million, respectively, of unrecognized tax benefits that, if recognized, would affect the effective tax rate.

We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2009 and 2008, we have approximately $12.5 million and $12.5 million, respectively, of accrued interest and penalties related to uncertain tax positions on the consolidated balance sheet. During 2009 and 2008, we recorded interest and penalties of $1.5 million and $3.0 million, respectively, through the consolidated statement of operations. During 2009, $1.5 million of accrued interest and penalties were transferred to Seahawk.

The following table presents the reconciliation of the total amounts of unrecognized tax benefits:

	2009			2008
Balance at the beginning of the year	$	45.1		$	44.4
Increase related to prior period tax positions		5.9			2.7
Increase related to current period tax positions		2.4			1.5
Settlements		(0.3	)		(2.8	)
Amounts transferred to Seahawk		(2.4	)		-
Recognition of benefits from clarification in tax laws		(5.1	)		-
Other		-			(0.7	)
Balance at the end of the year	$	45.6		$	45.1

For jurisdictions other than the United States, tax years 1999 through 2009 remain open to examination by the major taxing jurisdictions. With regard to the United States, tax years 2006 through 2009 remain open to examination.

From time to time, our periodic tax returns are subject to review and examination by various tax authorities within the jurisdictions in which we operate. We are currently contesting several tax assessments and may contest future assessments where we believe the assessments are in error. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments; however, we do not expect the ultimate resolution of outstanding tax assessments to have a material adverse effect on our consolidated financial statements.

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NOTE 9.  STOCKHOLDERS’ EQUITY

Preferred Stock

We are authorized to issue 50.0 million shares of preferred stock with a par value $0.01 per share. Our Board of Directors has the authority to issue shares of preferred stock in one or more series and to fix the number of shares, designations and other terms of each series. The Board of Directors has designated 4.0 million shares of preferred stock to constitute the Series A Junior Participating Preferred Stock in connection with our stockholders’ rights plan. As of December 31, 2009 and 2008, no shares of preferred stock were outstanding.

Common Stock

In connection with the retirement in the second quarter of 2008 of our 3¼% Convertible Senior Notes Due 2033, we issued a total of 5.0 million shares of common stock to the holders (See Note 5).

Stockholders’ Rights Plan

We have a preferred share purchase rights plan. Under the plan, each share of common stock includes one right to purchase preferred stock. The rights will separate from the common stock and become exercisable (1) ten days after public announcement that a person or group of affiliated or associated persons has acquired, or obtained the right to acquire, beneficial ownership of 15% of our outstanding common stock or (2) ten business days following the start of a tender offer or exchange offer that would result in a person’s acquiring beneficial ownership of 15% of our outstanding common stock. A 15% beneficial owner is referred to as an “acquiring person” under the plan. In 2008, our Board of Directors took action under the plan to reduce the applicable percentage of beneficial stock ownership that triggers the plan, only as it relates to Seadrill Limited and its affiliates and associates, from 15% to 10%.

Our Board of Directors can elect to delay the separation of the rights from the common stock beyond the ten-day periods referred to above. The plan also confers on the board the discretion to increase or decrease the level of ownership that causes a person to become an acquiring person. Until the rights are separately distributed, the rights will be evidenced by the common stock certificates and will be transferred with and only with the common stock certificates.

After the rights are separately distributed, each right will entitle the holder to purchase from us one one-hundredth of a share of Series A Junior Participating Preferred Stock for a purchase price of $50. The rights will expire at the close of business on September 30, 2011, unless we redeem or exchange them earlier as described below.

If a person becomes an acquiring person, the rights will become rights to purchase shares of our common stock for one-half the current market price, as defined in the rights agreement, of the common stock. This occurrence is referred to as a “flip-in event” under the plan. After any flip-in event, all rights that are beneficially owned by an acquiring person, or by certain related parties, will be null and void. Our Board of Directors has the power to decide that a particular tender or exchange offer for all outstanding shares of our common stock is fair to and otherwise in the best interests of our stockholders. If our Board of Directors makes this determination, the purchase of shares under the offer will not be a flip-in event.

If, after there is an acquiring person, we are acquired in a merger or other business combination transaction or 50% or more of our assets, earning power or cash flow are sold or transferred, each holder of a right will have the right to purchase shares of the common stock of the acquiring company at a price of one-half the current market price of that stock. This occurrence is referred to as a “flip-over event” under the plan. An acquiring person will not be entitled to exercise its rights, which will have become void.

Until ten days after the announcement that a person has become an acquiring person, our Board of Directors may decide to redeem the rights at a price of $0.01 per right, payable in cash, shares of common stock or other consideration. The rights will not be exercisable after a flip-in event until the rights are no longer redeemable.

At any time after a flip-in event and prior to either a person’s becoming the beneficial owner of 50% or more of the shares of common stock or a flip-over event, our Board of Directors may decide to exchange the rights for shares of common stock on a one-for-one basis. Rights owned by an acquiring person, which will have become void, will not be exchanged.

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NOTE 10.  EARNINGS PER SHARE

ASC Topic 260, Earnings Per Share, clarifies that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and should be included in the computation of earnings per share under the “two class” method. The “two class” method allocates undistributed earnings between common shares and participating securities. We have determined that our grants of unvested restricted stock awards are considered participating securities. We have prepared our current period earnings per share calculations and retrospectively revised our prior period calculations to exclude net income allocated to these unvested restricted stock awards. Basic and diluted income from continuing operations per share decreased by $0.03 and $0.01 for the years ended December 31, 2008 and 2007, respectively. We decreased basic and diluted net income per share by $0.05 and $0.04 for the years ended December 31, 2008 and 2007, respectively.

The following table presents information necessary to calculate basic and diluted earnings per share from continuing operations for the years ended December 31:

	2009			2008			2007
Income from continuing operations	$	340.3		$	508.7		$	256.3
Income from continuing operations allocated to non-vested share awards		(5.1	)		(5.4	)		(2.4	)
Income from continuing operations - basic		335.2			503.3			253.9
Interest expense on convertible notes		-			5.1			22.1
Income tax effect		-			(1.8	)		(7.7	)
Income from continuing operations - diluted	$	335.2		$	506.6		$	268.3
Weighted average shares of common stock outstanding - basic		173.7			170.6			165.6
Convertible notes		-			4.1			11.7
Stock options		0.3			0.5			0.8
Weighted average shares of common stock outstanding - diluted		174.0			175.2			178.1
Income from continuing operations per share:
Basic	$	1.93		$	2.95		$	1.54
Diluted	$	1.92		$	2.89		$	1.51

The calculation of weighted average shares of common stock outstanding - diluted, as adjusted, excludes 2.0 million, 1.2 million and 1.1 million of common stock issuable pursuant to outstanding stock options for the years ended December 31, 2009, 2008 and 2007, respectively, because their effect was antidilutive.

NOTE 11.  STOCK-BASED COMPENSATION

Our employee stock-based compensation plans provide for the granting or awarding of stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards and cash awards to directors, officers and other key employees. Under the terms of our stock-based compensation plans, the number of shares available for awards under the plans was adjusted pursuant to the terms of the plans to prevent dilution as a result of the spin-off of Seahawk.  This adjustment resulted in additional shares being made available for awards under the plans in the following amounts: 366,404 shares under our 2007 Long-Term Incentive Plan and 5,991 shares under our 2004 Directors' Stock Incentive Plan.  An adjustment was also made under our Employee Stock Purchase Plan to add an additional 8,798 shares available for issuance under the plan.

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As of December 31, 2009, two of our plans had shares available for future option grants or other awards. We had a total of approximately 89,000 shares available for award under the 2004 Directors’ Stock Incentive Plan. Under the 2007 Long-Term Incentive Plan, approximately 5.5 million shares are available for award, of which a maximum of approximately 2.6 million shares may be awards other than options and stock appreciation rights, such as restricted stock.

Stock-based compensation expense related to stock options, restricted stock and our ESPP was allocated as follows:

	2009
Operating costs, excluding depreciation and amortization	$	19.9
General and administrative, excluding depreciation and amortization		16.0
Stock-based compensation expense before income taxes		35.9
Income tax benefit		(10.3	)
Total stock-based compensation expense after income taxes	$	25.6

The fair value of stock option awards is estimated on the date of grant using the Black-Scholes-Merton model with the following weighted average assumptions:

	Stock Options			ESPP
	2009	2008	2007	2009
Dividend yield	0.0%	0.0%	0.0%	0.0%
Expected volatility	31.8%	35.1%	31.2%	31.8%
Risk-free interest rate	1.7%	3.3%	4.7%	1.7%
Expected life	5.3 years	5.3 years	6.3 years	0.5 years
Weighted average grant-date fair value of stock options granted	$           5.60	$         12.92	$         11.80	$           5.02

For the year ended December 31, 2009, we changed our methodology for estimating expected volatility from implied volatility calculated based on actively traded options on our common stock to a combination of historical volatility and peer group historical volatility.  This resulted in a change in our 2009 volatility, from 68.7% to 31.8%.  See Stock-Based Compensation in Note 1 of the Notes to Consolidated Financial Statements.

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The following table summarizes activity in our stock options:

			Weighted		Weighted
			Average		Average
			Exercise		Remaining	Aggregate
	Number of		Price per		Contractual	Intrinsic
	Shares		Share		Term	Value
	(In Thousands)				(In Years)
Outstanding as of December 31, 2008		2,644	$	26.77
Granted		1,460		17.52
Exercised		867		20.93
Forfeited		56		21.90
Expired		33		18.98
Outstanding as of December 31, 2009		3,148	$	22.77
Exercisable as of December 31, 2009		1,440	$	24.03	7.91	$           11.4

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The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between our closing stock price on the last trading day of the year and the exercise price, multiplied by the number of in-the-money stock options) that would have been received by the stock option holders had all the holders exercised their stock options on the last day of the year. This amount will change based on the market value of our stock.

In connection with the spin-off of Seahawk and pursuant to our stock-based compensation plans and in accordance with the requirements of U.S. federal income tax law, we modified the outstanding stock options to preserve the relative value of each option to the holder. The spin-off modifications resulted in an incremental increase in outstanding options of 270,912 and a corresponding incremental compensation expense of $1.1 million, of which $0.7 million is reflected in our income from continuing operations during the year ended December 31, 2009. The weighted average exercise price of the modified options was $22.39 and the weighted average fair value per share on the date of the spin-off was $9.55. The fair value per share was calculated using the Black-Scholes-Merton model with expected terms of 0.1 to 4.7 years, implied volatilities ranging from 41.51% to 45.67% and risk free interest rates ranging from 0.12% to 2.48%.

The exercise price of stock options is equal to the fair market value of our common stock on the option grant date. The stock options generally vest over periods ranging from two years to four years and have a contractual term of 10 years. Vested options may be exercised in whole or in part at any time prior to the expiration date of the grant.

Other information pertaining to option activity was as follows:

	2009		2008		2007
Total fair value of stock options vested	$	6.5	$	5.2	$	5.2
Total intrinsic value of stock options exercised	$	8.3	$	21.6	$	26.9

During 2009, 2008 and 2007, we received cash from the exercise of stock options of $18.0 million, $19.0 million and $27.6 million, respectively. Income tax benefits of $2.8 million, $7.9 million and $7.7 million were realized from the exercise of stock options for 2009, 2008 and 2007, respectively. As of December 31, 2009, there was $8.5 million of total stock option compensation expense related to nonvested stock options not yet recognized, which is expected to be recognized over a weighted average period of 1.8 years.

We have awarded restricted stock and restricted stock units (collectively, “restricted stock awards”) to certain key employees and directors. We record unearned compensation as a reduction of stockholders’ equity based on the closing price of our common stock on the date of grant. The unearned compensation is being recognized ratably over the applicable vesting period. Restricted stock awards consist of awards of our common stock, or awards denominated in common stock.

The following table summarizes the restricted stock awarded during the years ended December 31:

	2009		2008		2007
Number of restricted stock awards (in thousands)		1,917		932		948
Fair value of restricted stock awards at date of grant (in millions)	$	28.4	$	31.7	$	27.6

The following table summarizes activity in our nonvested restricted stock awards:

			Weighted
			Average
			Grant Date
	Number of		Fair Value
	Shares		per Share
	(In Thousands)
Nonvested at December 31, 2008		1,698	$	31.75
Granted		1,917		14.83
Vested		728		26.61
Forfeited		428		21.53
Nonvested at December 31, 2009		2,459	$	16.01

As of December 31, 2009, there was $39.4 million of unrecognized stock-based compensation expense related to nonvested restricted stock awards. That cost is expected to be recognized over a weighted average period of 1.7 years.

Unvested restricted stock unit awards granted during 2009, but prior to the Seahawk spin-off, were modified at the time of the spin-off to increase the number of units to reflect the stock dividend associated with the underlying shares. We granted 107,847 additional units, with a weighted average grant-date fair value per share of $26.54 on the date of the spin-off. Restricted stock unit awards that were granted prior to 2009 and were unvested at the time of the spin-off were not modified, but the holders received a cash dividend in lieu of additional units. As a result of Pride employees transferring to Seahawk, 189,592 restricted stock unit awards were forfeited.

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In December 2006, we changed the procedures regarding personal income tax withholding with respect to outstanding restricted stock awards held by our officers, including all of our executive officers. The changes permitted such officers to request that, for purposes of satisfying the federal income tax withholding obligations with respect to certain taxes required to be withheld with respect to the vesting of the awards, the amount withheld be greater than the statutory minimum with respect to federal income tax withholding but no more than the highest federal marginal income tax rate applicable to ordinary income at the time of vesting. For restricted stock awards that vested through February 14, 2007, the withholding of the statutory minimum and the increased amount was net settled by the plan administrator’s delivery of share of common stock to us with a fair market value equal to the amount of the withholding, with the remaining shares delivered to the officer. As a result of the change in procedures and the net settlement feature, these awards were reclassified from equity to liability awards in the fourth quarter of 2006. We reclassified $4.0 million from stockholders’ equity and accrued a total of $5.2 million in accrued expenses and other long-term liabilities for the fair value of the share-based payment liabilities at December 31, 2006. Expense of $1.2 million was recognized in 2006 in connection with the modification of these awards. As of February 15, 2007, we further amended our procedures for additional withholding and settlement of vested awards, which resulted in the reclassification of the affected restricted stock awards back to equity classified awards. The February 15, 2007, modification did not result in any material incremental compensation cost and resulted in the reclassification of the full amount of the recorded liability to equity in the first quarter of 2007.

During 2008 and 2007, we recognized $0.1 million and $0.1 million, respectively, of stock-based compensation in connection with the modification of the terms of certain key employees’ stock options and restricted stock.

Our ESPP permits eligible employees to purchase shares of our common stock at a price equal to 85% of the lower of the closing price of our common stock on the first or last trading day of the applicable purchase period.  Prior to 2009, the annual purchase period extended from January 1 to December 31 of each year.  Begining in 2009, there are two purchase periods of six months each. A total of 39,000 shares remained available for issuance under the plan as of December 31, 2009. Employees purchased approximately 202,000, 133,000 and 95,000 shares in the years ended December 31, 2009, 2008 and 2007, respectively.

NOTE 12.  EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have a non-qualified Supplemental Executive Retirement Plan (the “SERP”) that provides for benefits, to the extent vested, to be paid to participating executive officers upon the officer’s termination or retirement. No assets are held with respect to the SERP; therefore, benefits will be funded when paid to the participants. We recorded expenses of $3.4 million, $3.5 million and $5.6 million related to the SERP in 2009, 2008 and 2007, respectively. As of December 31, 2009 and 2008, the unfunded accrued pension liability was $22.1 million and $18.0 million, respectively.

We also have a post-retirement plan to provide medical benefits, to the extent vested, for participating executive officers upon the officer’s retirement or termination. The total liabilities for the underfunded plan were approximately $1.6 million as of December 31, 2009 and approximately $1.0 million as of December 31, 2008.

One of our foreign subsidiaries has a defined benefit pension plan covering substantially all of their eligible employees. Benefits under this plan are typically based on years of service and final average compensation levels. The plans are managed in accordance with applicable local statutes and practices. As of December 31, 2009 and 2008, based on the funded status of this plan, total assets for overfunded plans were approximately $0.6 million and $0.5 million, respectively.

Defined Contribution Plan

We have a 401(k) defined contribution plan for generally all of our U.S. employees that allows eligible employees to defer up to 50% of their eligible annual compensation, with certain limitations. At our discretion, we may match up to 100% of the first 6% of compensation deferred by participants. Our contributions to the plan amounted to $7.0 million, $9.2 million and $6.4 million in 2009, 2008 and 2007, respectively.

In addition, we have a deferred compensation plan that allows senior managers and other highly compensated employees, as defined in the plan, to participate in an unfunded, non-qualified plan. Participants may defer up to 100% of compensation, including bonuses and net proceeds from the exercise of stock options.

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NOTE 13.  COMMITMENTS AND CONTINGENCIES

Leases

At December 31, 2009, we had entered into long-term non-cancelable operating leases covering certain facilities and equipment. The minimum annual rental commitments are as follows for the years ending December 31:

	Amount
2010	$	10.5
2011		7.6
2012		6.7
2013		4.6
2014		4.2
Thereafter		14.4
	$	48.0

FCPA Investigation

During the course of an internal audit and investigation relating to certain of our Latin American operations, our management and internal audit department received allegations of improper payments to foreign government officials. In February 2006, the Audit Committee of our Board of Directors assumed direct responsibility over the investigation and retained independent outside counsel to investigate the allegations, as well as corresponding accounting entries and internal control issues, and to advise the Audit Committee.

The investigation has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.

The Audit Committee, through independent outside counsel, has undertaken a review of our compliance with the FCPA in certain of our other international operations.  This review has found evidence suggesting that during the period from 2001 through 2006 payments were made directly or indirectly to government officials in Saudi Arabia, Kazakhstan, Brazil, Nigeria, Libya, Angola and the Republic of the Congo in connection with clearing rigs or equipment through customs or resolving outstanding issues with customs, immigration, tax, licensing or merchant marine authorities in those countries. In addition, this review has found evidence suggesting that in 2003 payments were made to one or more third parties with the intent that they would be transferred to a government official in India for the purpose of resolving a customs dispute related to the importation of one of our jackup rigs. The evidence suggests that the aggregate amount of payments referred to in this paragraph is less than $2.5 million. In addition, the U.S. Department of Justice (“DOJ”) has asked us to provide information with respect to (a) our relationships with a freight and customs agent and (b) our importation of rigs into Nigeria.

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       The investigation of the matters described above and the Audit Committee’s compliance review are substantially complete. Our management and the Audit Committee of our Board of Directors believe it likely that then members of our senior operations management either were aware, or should have been aware, that improper payments to foreign government officials were made or proposed to be made. Our former Chief Operating Officer resigned as Chief Operating Officer effective on May 31, 2006 and has elected to retire from the company, although he will remain an employee, but not an officer, until the completion of the investigation and related matters to assist us with the investigation and to be available for consultation and to answer questions relating to our business.  His retirement benefits will be subject to the determination by our Audit Committee or our Board of Directors that it does not have cause (as defined in his retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.

We voluntarily disclosed information relating to the initial allegations and other information found in the investigation and compliance review to the DOJ and the SEC, and we have cooperated and continue to cooperate with these authorities.  For any violations of the FCPA, we may be subject to fines, civil and criminal penalties, equitable remedies, including profit disgorgement, and injunctive relief. Civil penalties under the antibribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 per violation and a company that knowingly commits a violation can be fined up to $25 million per violation. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly a monitor being appointed to review future business and practices with the goal of ensuring compliance with the FCPA.

We are engaged in discussions with the DOJ and the SEC regarding a potential negotiated resolution of these matters, which could be settled during 2010 and which, as described above, could involve a significant payment by us.  We believe that it is likely that any settlement will include both criminal and civil sanctions.  We have accrued $56.2 million in anticipation of a possible resolution with the DOJ and the SEC of potential liabilities under the FCPA. This accrual represents our best estimate of potential fines, penalties and disgorgement related to such resolution. For tax purposes, fines and penalties are not deductible. The monetary sanctions ultimately paid by us to resolve these issues, whether imposed on us or agreed to by settlement, may exceed the amount of the accrual.  There can be no assurance that our discussions with the DOJ and SEC will result in a final settlement of any or all of these issues or, if a settlement is reached, the timing of any such settlement or that the terms of any such settlement would not have a material adverse effect on us.

We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests.  We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our company.  For additional information regarding a stockholder demand letter with respect to these matters, please see the discussion below under “Demand Letter.”  In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets.  While we have made an accrual in anticipation of a possible resolution with the DOJ and SEC as discussed above, no amounts have been accrued related to any potential fines, sanctions, claims or other penalties referenced in this paragraph, which could be material individually or in the aggregate.

Although, as discussed above, we are currently in discussions with the DOJ and the SEC regarding a possible resolution of potential liability under the FCPA, we cannot currently predict what, if any, actions may be taken by the DOJ, the SEC, any other applicable government or other authorities or our customers or other third parties or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.

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Environmental Matters

       We are currently subject to pending notices of assessment issued from 2002 to 2009 pursuant to which governmental authorities in Brazil are seeking fines in an aggregate amount of less than $750,000 for releases of drilling fluids from rigs operating offshore Brazil. We are contesting these notices. We intend to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of these assessments to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these assessments.

We are currently subject to a pending administrative proceeding initiated in July 2009 by a governmental authority of Spain pursuant to which such governmental authority is seeking payment in an aggregate amount of approximately $4 million for an alleged environmental spill originating from the Pride North America while it was operating offshore Spain.  We expect to be indemnified for any payments resulting from this incident by our client under the terms of the drilling contract.  The client has posted guarantees with the Spanish government to cover potential penalties.  We intend to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of the proceeding to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of the proceeding.

Demand Letter

In June 2009, we received a demand letter from counsel representing Kyle Arnold.  The letter states that Mr. Arnold is one of our stockholders and that he believes that certain of our current and former officers and directors violated their fiduciary duties related to the issues described above under “—FCPA Investigation.”  The letter requests that our Board of Directors take appropriate action against the individuals in question.  In response to this letter, the Board has formed a special committee to evaluate the issues raised by the letter and determine a course of action for the company.  The committee has retained counsel to advise it.  Subsequent to the receipt of that demand letter, on October 14, 2009, Mr. Arnold filed suit in the state court of Harris County, Texas against us and certain of our current and former officers and directors.  The lawsuit, like the demand letter, alleged that the individual defendants breached their fiduciary duties to us related to the issues described above under “—FCPA Investigation.”  Among other remedies, the lawsuit sought damages and equitable relief against the individual defendants, along with an award of attorney fees and other costs and expenses to the plaintiff.  On October 16, 2009, the plaintiff dismissed the lawsuit without prejudice.  The special committee continues to evaluate these issues.

Loss of Pride Wyoming

In September 2008, the Pride Wyoming, a 250-foot slot-type jackup rig owned by Seahawk and operating in the U.S. Gulf of Mexico, was deemed a total loss for insurance purposes after it was severely damaged and sank as a result of Hurricane Ike.  All proceeds related to the insured value of the rig were received in 2008. Costs for removal of the wreckage are expected to be covered by our insurance.  Under the master separation agreement between us and Seahawk, Seahawk will be responsible for any removal costs, legal settlements and legal costs associated with the Pride Wyoming not covered by insurance.  At Seahawk's request, we will be required to finance, on a revolving basis, all of the costs for removal of the wreckage and salvage operations until receipt of insurance proceeds.  As of December 31, 2009, there were no amounts outstanding under this arrangement.

Potential Seahawk Tax-Related Guarantees

In 2006, 2007 and 2009, Seahawk received tax assessments from the Mexican government related to the operations of certain of Seahawk's subsidiaries. Seahawk is responsible for these assessments following the spin-off.  Pursuant to local statutory requirements, Seahawk has provided and may provide additional surety bonds or other suitable collateral to contest these assessments.  Pursuant to a tax support agreement between us and Seahawk, we have agreed, at Seahawk’s request, to guarantee or indemnify the issuer of any such surety bonds or other collateral issued for Seahawk’s account in respect of such Mexican tax assessments made prior to the spin-off date.  The amount of such bonds or other collateral could total up to approximately $143.0 million based on current exchange rates.  Beginning on July 31, 2012, on each subsequent anniversary thereafter, and on August 24, 2015, Seahawk will be required to provide substitute credit support for a portion of the collateral guaranteed or indemnified by us, so that our obligations are terminated in their entirety by August 24, 2015.  Pursuant to the tax support agreement, Seahawk is required to pay us a fee based on the actual credit support provided.  As of December 31, 2009, we had not provided any guarantee or indemnification for any surety bonds or other collateral under the tax support agreement.

Other

We are routinely involved in other litigation, claims and disputes incidental to our business, which at times involve claims for significant monetary amounts, some of which would not be covered by insurance. In the opinion of management, none of the existing litigation will have a material adverse effect on our financial position, results of operations or cash flows. However, a substantial settlement payment or judgment in excess of our accruals could have a material adverse effect on our financial position, results of operations or cash flows.

       In the normal course of business with customers, vendors and others, we have entered into letters of credit and surety bonds as security for certain performance obligations that totaled approximately $377.6 million at December 31, 2009. These letters of credit and surety bonds are issued under a number of facilities provided by several banks and other financial institutions.

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NOTE 14.  SEGMENT AND GEOGRAPHIC INFORMATION

We organize our reportable segments based on water depth operating capabilities of our drilling rigs. Our reportable segments include Deepwater, which consists of our rigs capable of drilling in water depths of 4,500 feet and greater; Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less; and Independent Leg Jackups, which consists of our rigs capable of operating in water depths up to 300 feet. We also manage the drilling operations for deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations.

The accounting policies for our segments are the same as those described in Note 1 of our Consolidated Financial Statements.

Summarized financial information for our reportable segments are listed below.

	2009			2008			2007
Deepwater revenues:
Revenues excluding reimbursables	$	810.3		$	874.6		$	636.5
Reimbursable revenues		12.8			7.6			7.3
Total Deepwater revenues		823.1			882.2			643.8
Midwater revenues:
Revenues excluding reimbursables		412.9			419.5			329.5
Reimbursable revenues		6.5			6.0			5.0
Total Midwater revenues		419.4			425.5			334.5
Independent Leg Jackup revenues:
Revenues excluding reimbursables		264.0			273.9			220.4
Reimbursable revenues		1.3			1.3			1.4
Total Independent Leg Jackup revenues		265.3			275.2			221.8
Other		83.0			119.2			127.9
Corporate		3.4			0.5			1.0
Total revenues	$	1,594.2		$	1,702.6		$	1,329.0
Earnings (loss) from continuing operations:
Deepwater	$	348.3		$	454.7		$	267.4
Midwater		129.0			163.6			141.4
Independent Leg Jackups		105.4			133.2			92.5
Other		4.8			7.8			59.3
Corporate		(174.2	)		(132.2	)		(142.4	)
Total	$	413.3		$	627.1		$	418.2
Capital expenditures:
Deepwater	$	893.6		$	714.4			336.8
Midwater		39.6			169.3			101.1
Independent Leg Jackups		11.6			40.1			39.6
Other		2.8			7.5			12.1
Corporate		21.8			29.4			21.9
Discontinued operations		25.0			23.3			144.9
Total	$	994.4		$	984.0		$	656.4
Depreciation and amortization:
Deepwater	$	76.7		$	72.2		$	83.9
Midwater		45.3			42.0			37.2
Independent Leg Jackups		29.0			26.8			26.3
Other		0.3			1.7			3.2
Corporate		7.7			4.6			2.5
Total	$	159.0		$	147.3		$	153.1

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       We measure segment assets as property and equipment and goodwill. As of December 31, 2008, we had goodwill of $1.2 million related to our former mat-supported jackup business which was subsequently distributed in the spin-off of this business in August 2009. Our total long-lived assets by segment as of December 31, 2009 and 2008 were as follows:

	2009		2008
Total long-lived assets:
Deepwater	$	3,836.1	$	3,014.5
Midwater		680.5		681.8
Independent Leg Jackups		261.2		276.0
Other		23.1		10.9
Corporate		89.4		81.8
Discontinued operations		-		529.1
Total	$	4,890.3	$	4,594.1

Our significant customers for the years ended December 31, 2009, 2008 and 2007, were as follows:

	2009	2008	2007
Petroleos Brasileiro S.A.	33%	25%	20%
Total S.A.	16%	13%	12%
BP America and affiliates	4%	13%	11%
Exxon Mobil Corporation	7%	11%	13%

For the year ended December 31, 2009 and 2008, we derived 97% and 96%, respectively, of our revenues from countries outside of the United States. As a result, we are exposed to the risk of changes in social, political and economic conditions inherent in foreign operations. Revenues by geographic area are presented by attributing revenues to the individual country where the services were performed.

Revenues by geographic area where the services are performed are as follows for years ended December 31:

	2009		2008		2007
Angola	$	489.6	$	532.1	$	464.8
Brazil		586.0		513.7		394.6
Other countries		469.3		592.0		402.7
All International		1,544.9		1,637.8		1,262.1
United States		49.3		64.8		66.9
Total	$	1,594.2	$	1,702.6	$	1,329.0

Long-lived assets by geographic area as presented in the following table were attributed to countries based on the physical location of the assets. A substantial portion of our assets is mobile. Asset locations at the end of the period are not necessarily indicative of the geographic distribution of the revenues generated by such assets during the periods.

Long-lived assets, which include property and equipment and goodwill, by geographic area, including our four drillships under construction in South Korea, are as follows at December 31:

	2009		2008
South Korea	$	1,682.3	$	965.5
Brazil		1,649.8		1,520.8
Angola		724.1		793.9
Mexico		0.8		343.3
Other countries		660.7		597.7
All International		4,717.7		4,221.2
United States		172.6		372.9
Total	$	4,890.3	$	4,594.1

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NOTE 15.  OTHER SUPPLEMENTAL INFORMATION

Prepaid expenses and other current assets consisted of the following at December 31:

	2009		2008
Other receivables	$	68.0	$	62.2
Prepaid expenses		23.5		31.0
Deferred mobilization and inspection costs		23.3		26.4
Insurance receivables		1.8		52.3
Other		6.7		5.5
Total	$	123.3	$	177.4

Accrued expenses and other current liabilities consisted of the following at December 31:

	2009		2008
Deferred mobilization revenues	$	65.5	$	78.1
Payroll and benefits		59.7		82.3
Department of Justice and Securities and Exchange Commission fines		56.2		-
Short-term indemnity		35.2		19.5
Interest		21.9		20.2
Current income taxes		13.9		70.7
Importation duties		13.6		7.5
Taxes other than income		5.4		18.9
Salvage costs		-		41.2
Other		68.3		65.0
Total	$	339.7	$	403.4

Supplemental consolidated statement of operations information is as follows for the years ended December 31:

	2009			2008		2007
Rental expense	$	48.7		$	46.8	$	43.1
Other income (loss), net
Foreign exchange gain (loss)	$	(5.5	)	$	10.2	$	(2.9	)
Realized and unrealized changes in fair value of derivatives		-			-		(1.0	)
Equity earnings in unconsolidated subsidiaries		-			0.2		1.0
Other		1.4			10.2		0.2
Total	$	(4.1	)	$	20.6	$	(2.7	)

Supplemental cash flows and non-cash transactions were as follows for the years ended December 31:

	2009			2008			2007
Decrease (increase) in:
Trade receivables	$	118.4		$	(101.2	)	$	(78.5	)
Prepaid expenses and other current assets		7.6			9.4			(0.7	)
Other assets		(18.3	)		(2.5	)		(19.0	)
Increase (decrease) in:
Accounts payable		(14.9	)		58.8			(53.5	)
Accrued expenses		44.1			(15.9	)		(15.6	)
Other liabilities		5.9			24.5			15.3
Net effect of changes in operating accounts	$	142.8		$	(26.9	)	$	(152.0	)
Cash paid during the year for:
Interest	$	70.2		$	56.1		$	77.6
Income taxes — U.S., net		0.6			2.4			8.6
Income taxes — foreign, net		123.7			145.8			127.6
Change in capital expenditures in accounts payable		24.0			(54.6	)		(50.6	)

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NOTE 16.  SELECTED QUARTERLY FINANCIAL DATA (1) (UNAUDITED)

	First		Second			Third			Fourth
	Quarter		Quarter			Quarter			Quarter
2009
Revenues	$	451.9	$	439.5		$	386.1		$	316.7
Earnings from operations		172.4		164.3			100.1			(23.5	)
Income from continuing operations, net of tax		148.9		134.7			79.9			(23.2	)
Income from discontinued operations, net of tax		10.0		(10.6	)		(44.3	)		(9.6	)
Net income		158.9		124.1			35.6			(32.8	)
Basic earnings per share:
Income from continuing operations	$	0.84	$	0.76		$	0.45		$	(0.13	)
Income from discontinued operations		0.06		(0.06	)		(0.25	)		(0.06	)
Net income	$	0.90	$	0.70		$	0.20		$	(0.19	)
Diluted earnings per share:
Income from continuing operations	$	0.84	$	0.76		$	0.45		$	(0.13	)
Income from discontinued operations		0.06		(0.06	)		(0.25	)		(0.06	)
Net income	$	0.90	$	0.70		$	0.20		$	(0.19	)
2008
Revenues	$	368.5	$	380.7		$	463.3		$	490.2
Earnings from operations		111.6		114.6			185.0			215.9
Income from continuing operations, net of tax		93.2		98.9			144.2			172.4
Income from discontinued operations, net of tax		146.8		88.4			44.9			62.3
Net income		240.0		187.3			189.1			234.7
Basic earnings per share:
Income from continuing operations	$	0.55	$	0.58		$	0.82		$	0.99
Income from discontinued operations		0.87		0.51			0.26			0.36
Net income	$	1.42	$	1.09		$	1.08		$	1.35
Diluted earnings per share:
Income from continuing operations	$	0.53	$	0.56		$	0.82		$	0.99
Income from discontinued operations		0.81		0.50			0.26			0.36
Net income	$	1.34	$	1.06		$	1.08		$	1.35

____________

(1) All periods presented reflect the reclassification of our former mat-supported jackup business, our former Latin America Land and E&P Services segments, three tender-assist barge rigs and remaining Eastern Hemisphere land rig operations to discontinued operations.

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

None.

ITEM 9A.  CONTROLS AND PROCEDURES

(a)  Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this annual report. Based upon that evaluation, our President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2009 were effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

(b)  Management’s Report on Internal Control Over Financial Reporting

  Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined under Rule 13a-15(f) promulgated under the Exchange Act. In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2009, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, using the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (the “COSO Framework”). The inherent limitations of internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Based on its assessment, management concluded that our internal control over financial reporting was effective based on the criteria set forth in the COSO Framework as of December 31, 2009.

KPMG LLP, our independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2009 as stated in their report, which appears in “Item 8. Financial Statements and Supplementary Data” contained herein.

(c)  Changes in Our Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the fourth quarter of 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.  OTHER INFORMATION

None.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, or the Exchange Act, within 120 days of the end of our fiscal year on December 31, 2009. Information with respect to our executive officers is set forth under the caption “Executive Officers of the Registrant” in Part I of this annual report.

Code of Business Conduct and Ethical Practices

We have adopted a Code of Business Conduct and Ethical Practices, which applies to all employees, including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of the code under “Corporate Governance” in the “Investor Relations” section of our internet website at www.prideinternational.com. Copies of the code may be obtained free of charge on our website. Any waivers of the code must be approved by our Board of Directors or a designated board committee. Any amendments to, or waivers from, the code that apply to our executive officers and directors will be posted under “Corporate Governance” in the “Investor Relations” section of our internet website at www.prideinternational.com.

ITEM 11.  EXECUTIVE COMPENSATION

The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2009.

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

The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2009.

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

The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2009.

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2009.

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PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this annual report:

(1) Financial Statements

All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10-K.

(2) Financial Statement Schedules

All financial statement schedules have been omitted because they are not applicable or not required, or the information required thereby is included in the consolidated financial statements or the notes thereto included in this annual report.

(3) Exhibits

Each exhibit identified below is filed with this annual report. Exhibits designated with an “*” are filed herewith and with an “**” are furnished herewith. Exhibits designated with a “†” are management contracts or compensatory plans or arrangements.

Exhibit No.	Description
2.1	Master Separation Agreement, dated as of August 4, 2009, between Pride International, Inc. and Seahawk Drilling, Inc. (incorporated by reference to Exhibit 2.1 to Pride’s Current Report on Form 8-K filed with the SEC on August 7, 2009, File No. 1-13289).
3.1	Certificate of Incorporation of Pride (incorporated by reference to Annex D to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4, Registration Nos. 333-66644 and 333-66644-01 (the “Registration Statement”)).
3.2	Bylaws of Pride, as amended on December 12, 2008 (incorporated by reference to Exhibit 3.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 18, 2008, File No. 1-13289).
4.1	Form of Common Stock Certificate (incorporated by reference to Exhibit 4.13 to the Registration Statement).
4.2	Rights Agreement, dated as of September 13, 2001, between Pride and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.2 Pride’s Current Report on Form 8-K filed with the SEC on September 28, 2001, File No. 1-13289 (the “Form 8-K”)).
4.3	First Amendment to Rights Agreement dated as of January 29, 2008 between Pride and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.3 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13289).
4.4	Certificate of Designations of Series A Junior Participating Preferred Stock of Pride (incorporated by reference to Exhibit 4.3 to the Form 8-K).
4.5	Revolving Credit Agreement dated as of December 9, 2008 among Pride, the lenders from time to time parties thereto, Citibank, N.A., as administrative agent for the lenders, Natixis, as syndication agent for the lenders, BNP Paribas, Bayerische Hypo-Und Vereinsbank AG and Wells Fargo Bank, N.A., as documentation agents for the lenders, and Citibank, N.A., as issuing bank of the letters of credit thereunder (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 15, 2008, File No. 1-13289).
4.6	Indenture dated as of July, 1, 2004 by and between Pride and The Bank of New York Mellon (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Pride’s Registration Statement on Form S-4, File No. 333-118104).
4.7	First Supplemental Indenture dated as of July 7, 2004 by and between Pride and The Bank of New York Mellon (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.2 to Pride’s Registration Statement on Form S-4, File No. 333-118104).
4.8	Second Supplemental Indenture dated as of June 2, 2009 by and between Pride and The Bank of New York Mellon (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13289).
	Pride and its subsidiaries are parties to several debt instruments that have not been filed with the SEC under which the total amount of securities authorized does not exceed 10% of the total assets of Pride and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, Pride agrees to furnish a copy of such instruments to the SEC upon request.
10.1†	Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10(j) to Pride’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-16963).
10.2†	First Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 4.7 to Pride’s Registration Statement on Form S-8, Registration No. 333-35093).
10.3†	Second Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.10 to Pride’s Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-13289).
10.4†	Third Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.11 of Pride’s Annual Report on Form 10-K for the year ended December 31, 1998, File No. 1-13289).
10.5†	Fourth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.12 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289).
10.6†	Fifth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.13 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289).
10.7†	Sixth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.5 to Pride’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-13289).
10.8†	Pride International, Inc. 401(k) Restoration Plan (incorporated by reference to Exhibit 10(k) to Pride’s Annual Report on Form 10-K for the year ended December 31, 1993, File No. 0-16963).
10.9†	Pride International, Inc. Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2009 (the “SERP”) (incorporated by reference to Exhibit 10.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13289).
10.10†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Louis A. Raspino (incorporated by reference to Exhibit 10.7 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.11†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Imran Toufeeq (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on August 14, 2009, File No. 1-13289).
10.12†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.9 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.13†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.10 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.14†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Lonnie D. Bane (incorporated by reference to Exhibit 10.11 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.15†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Kevin C. Robert (incorporated by reference to Exhibit 10.15 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13289).
10.16†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Rodney W. Eads (incorporated by reference to Exhibit 10.8 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.17†	Pride International, Inc. 1998 Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.21 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 1-13289).
10.18†	Form of 1998 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289).
10.19†	Form of 1998 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (with additional provisions) (incorporated by reference to Exhibit 10.4 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289).
10.20†	Form of 1998 Long-Term Incentive Plan Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289).
10.21†	Form of 1998 Long-Term Incentive Plan Restricted Stock Agreement (with additional provisions) (incorporated by reference to Exhibit 10.5 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289).
10.22†	Form of 1998 Long-Term Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289).
10.23†	Form of 1998 Long-Term Incentive Plan Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.6 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289).
10.24†	Pride International, Inc. Employee Stock Purchase Plan (as amended and restated effective January 1, 2009) (“ESPP”) (incorporated by reference to Exhibit 10.3 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
10.25†*	First Amendment to ESPP.
10.26†	Pride International, Inc. Annual Incentive Plan (as amended and restated effective January 1, 2008) (incorporated by reference to Exhibit 10.4 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
10.27†	Pride International, Inc. 2004 Directors’ Stock Incentive Plan (as amended and restated) (incorporated by reference to Appendix B to Pride’s Proxy Statement on Schedule 14A for the 2008 Annual Meeting of Stockholders, File No. 1-13289).
10.28†	First Amendment to 2004 Directors’ Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
10.29†	Form of 2004 Director’s Stock Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 6, 2005, File No. 1-13289).
10.30†	Form of 2004 Director’s Stock Incentive Plan Restricted Stock Agreement (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 6, 2005, File No. 1-13289).
10.31†	Form of 2004 Directors’ Stock Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289).
10.32†	Pride International, Inc. 2007 Long-Term Incentive Plan (incorporated by reference to Appendix B to Pride’s Proxy Statement on Schedule 14A for the 2007 Annual Meeting of Stockholders, File No. 1-13289).
10.33†	First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
10.34†	Form of 2007 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.35†	Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.36†	Form of 2007 Long-Term Incentive Plan Performance-Based Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.37†	Form of 2007 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (with additional provisions) (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.38†	Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.5 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.39†	Form of 2007 Long-Term Incentive Plan Performance-Based Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.6 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.40†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Louis A. Raspino (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.41†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Imran Toufeeq (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on August 14, 2009, File No. 1-13289).
10.42†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.43†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.44†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Lonnie D. Bane (incorporated by reference to Exhibit 10.5 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.45†	Amended and Restated Employment/Non- Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Kevin C. Robert (incorporated by reference to Exhibit 10.41 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 0-16963).
10.46†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Rodney W. Eads (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.47†*	Summary of certain executive officer and director compensation arrangements.
10.48	Tax Sharing Agreement, dated as of August 4, 2009, between Pride International, Inc. and Seahawk Drilling, Inc. (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on August 7, 2009, File No. 1-13289).
12*	Computation of ratio of earnings to fixed charges.
21*	Subsidiaries of Pride.
23.1*	Consent of KPMG LLP.
31.1*	Certification of Chief Executive Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of the Chief Executive Officer and the Chief Financial Officer of Pride pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema
101.LAB**	XBRL Taxonomy Extension Label Linkbase
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase
101.DEF**	XBRL Taxonomy Extension Definition Linkbase

88

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on February 19, 2010.

 PRIDE INTERNATIONAL, INC.

/s/ LOUIS A. RASPINO

 Louis A. Raspino

 President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 19, 2010.

Signatures	Title
/s/  LOUIS A. RASPINO	President, Chief Executive Officer and Director
(Louis A. Raspino)	(principal executive officer)
/s/  BRIAN C. VOEGELE	Senior Vice President and Chief Financial Officer
(Brian C. Voegele)	(principal financial officer)
/s/  LEONARD E. TRAVIS	Vice President and Chief Accounting Officer
(Leonard E. Travis)	(principal accounting officer)
/s/  DAVID A. B. BROWN	Chairman of the Board
(David A. B. Brown)
/s/  KENNETH M. BURKE	Director
(Kenneth M. Burke)
/s/  ARCHIE W. DUNHAM	Director
(Archie W. Dunham)
/s/  DAVID A. HAGER	Director
(David A. Hager)
/s/  FRANCIS S. KALMAN	Director
(Francis S. Kalman)
/s/  RALPH D. MCBRIDE	Director
(Ralph D. McBride)
/s/  ROBERT G. PHILLIPS	Director
(Robert G. Phillips)

89

INDEX TO EXHIBITS

Exhibit No.	Description
2.1	Master Separation Agreement, dated as of August 4, 2009, between Pride International, Inc. and Seahawk Drilling, Inc. (incorporated by reference to Exhibit 2.1 to Pride’s Current Report on Form 8-K filed with the SEC on August 7, 2009, File No. 1-13289).
3.1	Certificate of Incorporation of Pride (incorporated by reference to Annex D to the Joint Proxy Statement/Prospectus included in the Registration Statement on Form S-4, Registration Nos. 333-66644 and 333-66644-01 (the “Registration Statement”)).
3.2	Bylaws of Pride, as amended on December 12, 2008 (incorporated by reference to Exhibit 3.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 18, 2008, File No. 1-13289).
4.1	Form of Common Stock Certificate (incorporated by reference to Exhibit 4.13 to the Registration Statement).
4.2	Rights Agreement, dated as of September 13, 2001, between Pride and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.2 Pride’s Current Report on Form 8-K filed with the SEC on September 28, 2001, File No. 1-13289 (the “Form 8-K”)).
4.3	First Amendment to Rights Agreement dated as of January 29, 2008 between Pride and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 4.3 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13289).
4.4	Certificate of Designations of Series A Junior Participating Preferred Stock of Pride (incorporated by reference to Exhibit 4.3 to the Form 8-K).
4.5	Revolving Credit Agreement dated as of December 9, 2008 among Pride, the lenders from time to time parties thereto, Citibank, N.A., as administrative agent for the lenders, Natixis, as syndication agent for the lenders, BNP Paribas, Bayerische Hypo-Und Vereinsbank AG and Wells Fargo Bank, N.A., as documentation agents for the lenders, and Citibank, N.A., as issuing bank of the letters of credit thereunder (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 15, 2008, File No. 1-13289).
4.6	Indenture dated as of July, 1, 2004 by and between Pride and The Bank of New York Mellon (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Pride’s Registration Statement on Form S-4, File No. 333-118104).
4.7	First Supplemental Indenture dated as of July 7, 2004 by and between Pride and The Bank of New York Mellon (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.2 to Pride’s Registration Statement on Form S-4, File No. 333-118104).
4.8	Second Supplemental Indenture dated as of June 2, 2009 by and between Pride and The Bank of New York Mellon (successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13289).
	Pride and its subsidiaries are parties to several debt instruments that have not been filed with the SEC under which the total amount of securities authorized does not exceed 10% of the total assets of Pride and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, Pride agrees to furnish a copy of such instruments to the SEC upon request.
10.1†	Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10(j) to Pride’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-16963).
10.2†	First Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 4.7 to Pride’s Registration Statement on Form S-8, Registration No. 333-35093).
10.3†	Second Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.10 to Pride’s Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-13289).
10.4†	Third Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.11 of Pride’s Annual Report on Form 10-K for the year ended December 31, 1998, File No. 1-13289).
10.5†	Fourth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.12 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289).
10.6†	Fifth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.13 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289).
10.7†	Sixth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.5 to Pride’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-13289).
10.8†	Pride International, Inc. 401(k) Restoration Plan (incorporated by reference to Exhibit 10(k) to Pride’s Annual Report on Form 10-K for the year ended December 31, 1993, File No. 0-16963).
10.9†	Pride International, Inc. Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2009 (the “SERP”) (incorporated by reference to Exhibit 10.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, File No. 1-13289).
10.10†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Louis A. Raspino (incorporated by reference to Exhibit 10.7 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.11†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Imran Toufeeq (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on August 14, 2009, File No. 1-13289).
10.12†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.9 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.13†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.10 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.14†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Lonnie D. Bane (incorporated by reference to Exhibit 10.11 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.15†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Kevin C. Robert (incorporated by reference to Exhibit 10.15 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-13289).
10.16†	Amended SERP Participation Agreement dated December 31, 2008 between Pride and Rodney W. Eads (incorporated by reference to Exhibit 10.8 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.17†	Pride International, Inc. 1998 Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.21 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 1-13289).
10.18†	Form of 1998 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289).
10.19†	Form of 1998 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (with additional provisions) (incorporated by reference to Exhibit 10.4 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289).
10.20†	Form of 1998 Long-Term Incentive Plan Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289).
10.21†	Form of 1998 Long-Term Incentive Plan Restricted Stock Agreement (with additional provisions) (incorporated by reference to Exhibit 10.5 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289).
10.22†	Form of 1998 Long-Term Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on December 29, 2006, File No. 1-13289).
10.23†	Form of 1998 Long-Term Incentive Plan Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.6 to the amendment to Pride’s Current Report on Form 8-K/A filed with the SEC on February 16, 2007, File No. 1-13289).
10.24†	Pride International, Inc. Employee Stock Purchase Plan (as amended and restated effective January 1, 2009) (“ESPP”) (incorporated by reference to Exhibit 10.3 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
10.25†*	First Amendment to ESPP.
10.26†	Pride International, Inc. Annual Incentive Plan (as amended and restated effective January 1, 2008) (incorporated by reference to Exhibit 10.4 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
10.27†	Pride International, Inc. 2004 Directors’ Stock Incentive Plan (as amended and restated) (incorporated by reference to Appendix B to Pride’s Proxy Statement on Schedule 14A for the 2008 Annual Meeting of Stockholders, File No. 1-13289).
10.28†	First Amendment to 2004 Directors’ Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
10.29†	Form of 2004 Director’s Stock Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 6, 2005, File No. 1-13289).
10.30†	Form of 2004 Director’s Stock Incentive Plan Restricted Stock Agreement (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 6, 2005, File No. 1-13289).
10.31†	Form of 2004 Directors’ Stock Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on December 31, 2008, File No. 1-13289).
10.32†	Pride International, Inc. 2007 Long-Term Incentive Plan (incorporated by reference to Appendix B to Pride’s Proxy Statement on Schedule 14A for the 2007 Annual Meeting of Stockholders, File No. 1-13289).
10.33†	First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
10.34†	Form of 2007 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.35†	Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.36†	Form of 2007 Long-Term Incentive Plan Performance-Based Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.37†	Form of 2007 Long-Term Incentive Plan Non-Qualified Stock Option Agreement (with additional provisions) (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.38†	Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.5 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.39†	Form of 2007 Long-Term Incentive Plan Performance-Based Restricted Stock Unit Agreement (with additional provisions) (incorporated by reference to Exhibit 10.6 to Pride’s Current Report on Form 8-K filed with the SEC on January 29, 2010, File No. 1-13289).
10.40†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Louis A. Raspino (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.41†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Imran Toufeeq (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on August 14, 2009, File No. 1-13289).
10.42†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.3 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.43†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.4 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.44†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Lonnie D. Bane (incorporated by reference to Exhibit 10.5 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10. 45†	Amended and Restated Employment/Non- Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Kevin C. Robert (incorporated by reference to Exhibit 10.41 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 0-16963).
10.46†	Amended and Restated Employment/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Rodney W. Eads (incorporated by reference to Exhibit 10.2 to Pride’s Current Report on Form 8-K filed with the SEC on January 7, 2009, File No. 1-13289).
10.47†*	Summary of certain executive officer and director compensation arrangements.
10.48	Tax Sharing Agreement, dated as of August 4, 2009, between Pride International, Inc. and Seahawk Drilling, Inc. (incorporated by reference to Exhibit 10.1 to Pride’s Current Report on Form 8-K filed with the SEC on August 7, 2009, File No. 1-13289).
12*	Computation of ratio of earnings to fixed charges.
21*	Subsidiaries of Pride.
23.1*	Consent of KPMG LLP.
31.1*	Certification of Chief Executive Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of the Chief Executive Officer and the Chief Financial Officer of Pride pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema
101.LAB**	XBRL Taxonomy Extension Label Linkbase
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase
101.DEF**	XBRL Taxonomy Extension Definition Linkbase

____________

*	Filed herewith.
**	Furnished herewith.
†	Management contract or compensatory plan or arrangement.

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