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, 2010

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

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 o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of the Act. Yes o 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 o

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 o

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 o	Non-accelerated filer o	Smaller reporting company o
		(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 o No þ

The aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2010, based on the closing price on the New York Stock Exchange on such date, was approximately $3.9 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 14, 2011 was 177,036,269.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the Annual Meeting of Stockholders to be held in May 2011 are incorporated by reference into Part III of this annual report.

TABLE OF CONTENTS

	Page
PART I
Item 1. Business		3
Item 1A. Risk Factors		11
Item 1B. Unresolved Staff Comments		25
Item 2. Properties		25
Item 3. Legal Proceedings		25
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
Item 6. Selected Financial Data		27
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk		54
Item 8. Financial Statements and Supplementary Data		55
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		89
Item 9A. Controls and Procedures		89
Item 9B. Other Information		89
PART III
Item 10. Directors, Executive Officers and Corporate Governance		90
Item 11. Executive Compensation		91
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		91
Item 13. Certain Relationships and Related Transactions, and Director Independence		91
Item 14. Principal Accounting Fees and Services		91
PART IV
Item 15. Exhibits, Financial Statement Schedules		92
Exhibit 10.49
Exhibit 10.55
Exhibit 12
Exhibit 21
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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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 18, 2011, a fleet of 26 rigs, consisting of five deepwater drillships, 12 semisubmersible rigs, seven jackups and two managed deepwater drilling rigs. We also have two 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.

On February 6, 2011, we entered into a merger agreement with Ensco plc and two of its subsidiaries. Pursuant to the merger agreement and subject to the conditions provided in the agreement, we will merge with one of the subsidiaries and become an indirect, wholly owned subsidiary of Ensco. The combination will create the industry’s second-largest offshore drilling fleet. Please read Note 17 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report for additional information about the terms of the transaction, our covenants under the merger agreement and the conditions to consummation of the transaction, as well as the financing commitments relating to the transaction. Please also read “Risk Factors” included in Item 1A. of Part I of this annual report for more information regarding risks relating to the transaction.

Our primary strategic focus is on ownership and operation of floating offshore rigs, particularly deepwater rigs. Although crude oil prices have declined from the record levels reached in mid-2008, they have maintained a trading range in excess of $60 per barrel since August 2009, averaging approximately $80 per barrel in 2010, with a high closing price per barrel of $91.48 in December 2010. The market for deepwater drilling services remains uncertain in the near term, due especially to continued concern stemming from the global recession and the Macondo well incident in the U.S. Gulf of Mexico in April 2010. However, we believe the long-term prospects for deepwater drilling are positive given 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, including enhanced reservoir recovery techniques. Since 2005, we have invested or committed to invest over $4.4 billion in the expansion of our deepwater fleet, including five new ultra-deepwater drillships, three of which were delivered in the first and third quarters of 2010 and the first quarter of 2011, and two of which are under construction with expected delivery dates in the fourth quarter of 2011 and third quarter of 2013. The three new drillships that have been delivered have multi-year contracts at favorable rates. Since 2005, we also have disposed of non-core assets, generating $1.6 billion in proceeds, enabling us to focus increasingly our financial and human capital on deepwater drilling.

As crude oil prices rose over the second half of 2009 through 2010, global exploration and production spending increased by an estimated 10% in 2010, according to the Barclays Capital E&P Spending Survey, which analyzes worldwide exploration and production trends. The increase follows an estimated 15% decline in 2009 that resulted primarily from the economic downturn and decline in crude oil prices. We anticipate that deepwater activity will outperform other offshore 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, 2010, totals $6.4 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.

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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 18, 2011:

			Water		Drilling
			Depth		Depth
		Built /	Rating		Rating
Rig Name	Rig Type / Design	Upgraded	(In Feet)		(In Feet)		Location	Status
Deepwater
Drillships Under Construction — 2
Deep Ocean Molokai	Samsung, DP3	Exp Q4 2011		12,000		40,000	S. Korea	Shipyard
PS-5	Samsung, DP3	Exp Q3 2013		12,000		40,000	S. Korea	Shipyard
Drillships — 5
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
Deep Ocean Ascension	Samsung, DP3	2010		12,000		40,000	USA	Mobilizing
Deep Ocean Clarion	Samsung, DP3	2010		12,000		40,000	USA	Mobilizing
Deep Ocean Mendocino	Samsung, DP3	2011		12,000		40,000	USA	Mobilizing
Semisubmersibles — 6
Pride North America	Bingo 8000	1999		7,500		25,000	Mediterranean	Mobilizing
Pride South Pacific	Sonat Offshore /Aker	1974/1999/2009		6,500		25,000	Equitorial	Working
							Guinea
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	2000/2010		5,600		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	Brazil	Working
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	Stacked
Independent Leg Jackup Rigs - 7
Pride Cabinda	Independent leg, cantilever	1983		300		25,000	Cameroon	Mobilizing
Pride Hawaii	Independent leg, cantilever	1975/1997		300		21,000	Bahrain	Stacked
Pride Pennsylvania	Independent leg, cantilever	1973/1998		300		20,000	Bahrain	Stacked
Pride Tennessee	Independent leg, cantilever	1981/2007		300		20,000	USA	Stacked
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
Kizomba	Tension Leg Platform Rig	2004		5,000		20,000	Angola	Working
Thunder Horse	Moored Semisubmersible Drilling Rig	2004		6,000		25,000	USA	Working

(1) Outfitted for workover activity

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Drillships. Our drillships, including the two 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 with quarters for up to 200 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 (referred to as conventional mooring) 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, 2010, Petroleo Brasilerio S.A., Total S.A. and BP America and affiliates accounted for 38%, 18%, and 15%, 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 we may enter into 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 if, due to government actions, a customer is no longer able to operate in, or it is no longer economical to operate in, certain regions. 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 or due to government actions in response to extraordinary events such as the Macondo well incident in the U.S. Gulf of Mexico in April 2010. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — U.S. Gulf of Mexico” in Item 7 of this annual report for a discussion of the Macondo well incident and related events. 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 September 2010, the rig was awarded a three-year contract commencing in January 2012. 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. In 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. In 2010, the Pride North America was awarded a one-well (estimated 30-day) contract that began in February 2011. The contract contains options for up to seven additional wells which may be exercised at the customer’s discretion. At this time we have not received notification from the customer regarding its intent with respect to these options, although the customer is not obligated to do so until we commence drilling the first well, which is expected to occur by the end of February 2011. The Pride South Pacific was awarded a one-year contract in 2009 commencing in January 2010. The contract was extended to March 2011. We are currently evaluating contract opportunities for the Pride North America and Pride South Pacific that, if awarded, would close all or a substantial portion of the available rig days in 2011. For information about the contract status of our three newly delivered drillships and our two drillships under construction, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments” 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. In July 2010, the Pride Venezuela completed a rig refurbishment project in a shipyard in Dubai and following mobilization commenced a one-year contract in October 2010. The Pride South Seas was cold stacked in the second quarter of 2010 due to the lack of near to intermediate term prospects. Recently, however, client interest in this rig has developed and, as a result, we are currently in the process of reactivating and marketing it to fill client needs in 2011.

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Independent Leg Jackups

During 2010, our two independent leg jackup rigs in the U.S. Gulf of Mexico, the Pride Wisconsin and Pride Tennessee, were cold stacked, with limited prospects for work. Recently, however, client interest in the Pride Tennessee has developed and we are currently evaluating the feasibility of reactivating the rig to fill client needs in 2011. Of our five independent leg jackup rigs outside the U.S. Gulf of Mexico, the Pride Montana is under contract to June 2011, the Pride North Dakota to November 2013, following a three-year contract extension awarded in 2010, and the Pride Cabinda to September 2011, following a five-month contract awarded in early 2011. The Pride Pennsylvania and Pride Hawaii completed three-year contracts in October 2009 and May 2010, respectively. Both rigs are cold stacked in a shipyard in Bahrain.

Other Operations

Other operations include our deepwater drilling operations management contracts and other operating activities. Our two current management contracts expire in 2012 and 2015 (with early termination permitted in certain cases). In addition, we had one management contract that ended in the third quarter of 2009 and another that ended in the fourth quarter of 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 and Indemnification Matters

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, punch throughs, craterings, fires, explosions and pollution. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. Our 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. Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well control and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. Our insurance policies typically consist of 12-month policy periods, with the next renewal date for a substantial portion of our insurance program being June 30, 2011.

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Our insurance program provides coverage, to the extent not otherwise paid by the customer under the indemnification provisions of the drilling contract, for liability due to control-of-well events, liability arising from named windstorms and liability arising from third-party claims, including wrongful death and other personal injury claims by our personnel as well as claims brought on behalf of individuals who are not our employees. The program also provides coverage for certain lost revenue on some of our assets with higher dayrates. Generally, our program provides liability coverage up to $850 million, with a retention of $1 million or less.

Control-of-well events generally include an unintended flow from the well that cannot be contained by using equipment on site (e.g., a blowout preventer), by increasing the weight of drilling fluid or by diverting the fluids safely into production. Our program provides coverage for third-party liability claims relating to pollution from a control-of-well event up to $600 million per occurrence, with the first $100 million of such coverage also covering re-drilling of the well and control-of-well costs. Our program also provides coverage for liability resulting from pollution originating from our rig up to $500 million per occurrence. We retain the risk for liability not indemnified by the customer in excess of our insurance coverage. In addition, our insurance program covers only sudden and accidental pollution.

Our insurance program also provides coverage for physical damage to, including total loss or constructive total loss of, our rigs, generally excluding damage arising from a named windstorm in the U.S. Gulf of Mexico. This coverage is based on an agreed amount for each rig, and has a $10 million annual aggregate deductible for losses that exceed a separate $10 million per occurrence deductible. We expect to purchase $110 million of named windstorm coverage for the Deep Ocean Mendocino. It is currently planned that this rig will remain in the U.S. Gulf of Mexico during the 2011 hurricane season.

Our drilling contracts provide for varying levels of indemnification from our customers and in most cases may require us to indemnify our customers. Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property. However, in certain drilling contracts we assume liability for damage to our customer’s property and other third-party property on the rig resulting from our negligence, subject to negotiated caps up to $1 million per occurrence, and in other contracts we are not indemnified by our customers for damage to their property and, accordingly, could be liable for any such damage under applicable law. In addition, our customers typically indemnify us for damage to our down-hole equipment, and in some cases our subsea equipment, generally based on replacement cost minus some level of depreciation.

Our customers typically assume responsibility for and indemnify us from any loss or liability resulting from pollution or contamination, including clean-up and removal and third-party damages, arising from operations under the contract and originating below the surface of the water, including as a result of blow-outs or cratering of the well. In some drilling contracts, however, we may have liability for third-party damages resulting from such pollution or contamination caused by our gross negligence, or, in some cases, ordinary negligence, subject to negotiated caps up to $10 million per occurrence.

We generally indemnify the customer for legal and financial consequences of spills of industrial waste and other liquids originating from our rigs or equipment above the surface of the water. Our contracts with Petrobras in Brazil typically provide that, in the event of any spill of petroleum, oil or other residues into the sea from our rigs, we are responsible for damages up to a capped amount not exceeding $1 million, without regard to our negligence.

For additional information, please read the risk factor captioned “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” in Item 1A of this annual report.

The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the date hereof and is general in nature. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.

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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 Bureau of Ocean Energy Management, Regulation and Enforcement of the U.S. Department of the Interior (“BOEM”), at the time known as the Minerals Management Service, 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. Further, following the Macondo well incident in the U.S. Gulf of Mexico in April 2010, BOEM implemented various environmental, technological and safety measures intended to improve offshore safety systems and environmental protection. Implementation of new BOEM 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 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments — U.S. Gulf of Mexico” in Item 7 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.

Employees

As of December 31, 2010, we employed approximately 3,900 personnel and had approximately 400 contract personnel working for us. Approximately 980 of our employees and contractors were located in the United States and 3,320 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.

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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

• 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.

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While recent economic trends have stabilized, continued effects of the economic recession could lead to a decline in demand for crude oil and natural gas. Further slowdowns 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. 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. 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, due to government actions 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. Further, due to government actions, a customer may no longer be able to operate in, or it may not be economical to operate in, certain regions. 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.

The Macondo well incident in the U.S. Gulf of Mexico in April 2010 and its consequences could have a material adverse effect on our business.

The Macondo well incident in the U.S. Gulf of Mexico in April 2010 and its consequences, including actions taken, or that may be taken, by the U.S. government, other governments or our customers, could have a material adverse effect on our business. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments — Drillships Construction Projects”, “— Recent Developments — Recently Delivered Drillships” and “— Recent Developments — U.S. Gulf of Mexico” in Item 7 of this annual report.

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 our drillship construction projects. 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 2011, we expect to spend approximately $800 million with respect to our drillship construction projects, and an additional approximately $265 million with respect to the refurbishment and upgrade of other rigs.

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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;

• 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;

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

• 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;

• 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 two 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, 88 jackup rigs have been added to the global fleet, with another 47 expected to be added in 2011 and 2013. 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, 21 drillships and 36 new semi-submersible rigs entered the market from 2007 through 2010, and there have been announcements of approximately 54 new semisubmersible rigs and drillships with delivery forecasted to occur from 2011 through 2014, including our two remaining 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, safety records 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. 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 continue to sustain some losses of experienced personnel to our customers and competitors. Our labor costs have increased significantly since 2005 and, while this trend moderated 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 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 2010, we derived 94% of our revenues from countries outside the United States, including 51% from Brazil and 22% from Angola. 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.

Some of our risks are concentrated because of our substantial operations in Brazil and Angola.

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 have resolved with the U.S. Department of Justice and the Securities and Exchange Commission our previously disclosed investigations into potential violations of the U.S. Foreign Corrupt Practices Act. We cannot currently predict what, if any, actions may be taken by any other applicable government or other authorities or our customers or other third parties or the effect the actions may have.

We have resolved with the U.S. Department of Justice and the Securities and Exchange Commission our previously disclosed investigations into potential violations of the U.S. Foreign Corrupt Practices Act. In connection with the settlements, in the fourth quarter of 2010 we paid a total of $56.2 million in penalties, disgorgement and interest as described below. We had accrued this amount in the fourth quarter of 2009.

The settlement with the DOJ included a deferred prosecution agreement (“DPA”) between us and the DOJ and a guilty plea by our French subsidiary, Pride Forasol S.A.S., to FCPA-related charges. Under the DPA, the DOJ agreed to defer the prosecution of certain FCPA-related charges against us and agreed not to bring any further criminal or civil charges against us or any of our subsidiaries related to either any of the conduct set forth in the statement of facts attached to the DPA or any other information we disclosed to the DOJ prior to the execution of the DPA. We agreed, among other things, to continue to cooperate with the DOJ, to continue to review and maintain our anti-bribery compliance program and to submit to the DOJ three annual written reports regarding our progress and experience in maintaining and, as appropriate, enhancing our compliance policies and procedures. If we comply with the terms of the DPA, the deferred charges against us will be dismissed with prejudice. If, during the term of the DPA, the DOJ determines that we have committed a felony under federal law, provided deliberately false information or otherwise breached the DPA, we could be subject to prosecution and penalties for any criminal violation of which the DOJ has knowledge, including the deferred charges.

In December 2010, pursuant to a plea agreement, Pride Forasol S.A.S. pled guilty in U.S. District Court to conspiracy and FCPA charges. Pride Forasol S.A.S. was sentenced to pay a criminal fine of $32.6 million and to serve a three-year term of organizational probation.

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The SEC investigation was resolved in November 2010. Without admitting or denying the allegations in a civil complaint filed by the SEC, we consented to the entry of a final judgment ordering disgorgement plus pre-judgment interest totaling $23.6 million and a permanent injunction against future violations of the FCPA.

We have received preliminary inquiries from governmental authorities of certain of the countries referenced in our settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other 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. At this early stage of such inquiries, we are unable to determine what, if any, legal liability may result. 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 and derivative cases with respect to these matters, please see the discussion under “— Demand Letter and Derivative Cases” in Note 12 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report. In addition, disclosure of the subject matter of the investigations and settlements 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. 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.

We cannot currently predict what, if any, actions may be taken by 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.

In addition, in connection with the investigation, our former Chief Operating Officer resigned as an officer effective May 31, 2006 and remained in the capacity of an employee to assist us with the investigation and to be available for consultation and to answer questions relating to our business. He had agreed to retire upon the conclusion of the investigation, and his right to receive retirement benefits was subject to the determination by our board of directors that we did not have cause (as defined in his retirement agreement with us) to terminate his employment. The board of directors recently determined that we did not have requisite cause to terminate his employment and that his retirement date was December 31, 2010.

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 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.

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

Neither of our two drillships currently under construction have long-term drilling contracts. One of the two uncontracted drillships is scheduled for delivery in the fourth quarter of 2011 and the other is scheduled for delivery in mid-2013. 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 drilling contracts for rigs under construction, including our remaining uncontracted drillship construction projects, prior to deployment could adversely affect our results of operations and financial condition.

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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 2010, a majority of our revenue was derived from long-term dayrate contracts, and substantially all of our backlog as of December 31, 2010 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, 2010, our contract drilling backlog was approximately $6.4 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 2011 and 2014 of approximately 101 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.

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, 2010, our three largest customers provided approximately 72% 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.

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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, 2010, we had $1,863.7 million in debt. This debt represented approximately 29% 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 two remaining 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, punch throughs, craterings, fires, explosions and pollution. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. Our 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. Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well control and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. Our insurance policies typically consist of 12-month policy periods, with the next renewal date for a substantial portion of our insurance program being June 30, 2011.

Our insurance program provides coverage, to the extent not otherwise paid by the customer under the indemnification provisions of the drilling contract, for liability due to control-of-well events, liability arising from named windstorms and liability arising from third-party claims, including wrongful death and other personal injury claims by our personnel as well as claims brought on behalf of individuals who are not our employees. The program also provides coverage for certain lost revenue on some of our assets with higher dayrates. Generally, our program provides liability coverage up to $850 million, with a retention of $1 million or less.

Control-of-well events generally include an unintended flow from the well that cannot be contained by using equipment on site (e.g., a blowout preventer), by increasing the weight of drilling fluid or by diverting the fluids safely into production. Our program provides coverage for third-party liability claims relating to pollution from a control-of-well event up to $600 million per occurrence, with the first $100 million of such coverage also covering re-drilling of the well and control-of-well costs. Our program also provides coverage for liability resulting from pollution originating from our rig up to $500 million per occurrence. We retain the risk for liability not indemnified by the customer in excess of our insurance coverage. In addition, our insurance program covers only sudden and accidental pollution.

Our insurance program also provides coverage for physical damage to, including total loss or constructive total loss of, our rigs, generally excluding damage arising from a named windstorm in the U.S. Gulf of Mexico. This coverage is based on an agreed amount for each rig, and has a $10 million annual aggregate deductible for losses that exceed a separate $10 million per occurrence deductible. We expect to purchase $110 million of named windstorm coverage for the Deep Ocean Mendocino. It is currently planned that this rig will remain in the U.S. Gulf of Mexico during the 2011 hurricane season.

19

Our drilling contracts provide for varying levels of indemnification from our customers and in most cases may require us to indemnify our customers. Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property. However, in certain drilling contracts we assume liability for damage to our customer’s property and other third-party property on the rig resulting from our negligence, subject to negotiated caps up to $1 million per occurrence, and in other contracts we are not indemnified by our customers for damage to their property and, accordingly, could be liable for any such damage under applicable law. In addition, our customers typically indemnify us for damage to our down-hole equipment, and in some cases our subsea equipment, generally based on replacement cost minus some level of depreciation.

Our customers typically assume responsibility for and indemnify us from any loss or liability resulting from pollution or contamination, including clean-up and removal and third-party damages, arising from operations under the contract and originating below the surface of the water, including as a result of blow-outs or cratering of the well. In some drilling contracts, however, we may have liability for third-party damages resulting from such pollution or contamination caused by our gross negligence, or, in some cases, ordinary negligence, subject to negotiated caps up to $10 million per occurrence.

We generally indemnify the customer for legal and financial consequences of spills of industrial waste and other liquids originating from our rigs or equipment above the surface of the water. Our contracts with Petrobras in Brazil typically provide that, in the event of any spill of petroleum, oil or other residues into the sea from our rigs, we are responsible for damages up to a capped amount not exceeding $1 million, without regard to our negligence.

The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the date hereof and is general in nature. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.

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.

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.

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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 Clean Air Act (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; (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, which allowed the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crude oil); and (iii) a final rule, effective August 2, 2010, to address permitting of GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Finally, on November 8, 2010, the EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to the EPA’s GHG reporting rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year will now be required to report annual GHG emissions to EPA, with the first report due on March 31, 2012.

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 customers’ operations.

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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. The BOEM has issued guidelines for jackup rig fitness requirements during hurricane seasons, which are scheduled to be effective through the 2013 hurricane season. As a result of these BOEM 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 BOEM may take other steps that could increase the cost of operations or reduce the area of operations. Implementation of the BOEM guidelines or regulations may subject us to increased costs and limit the operational capabilities of our rigs.

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.

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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 Proposed Merger with Ensco

Failure to complete or delays in completing the merger could have an adverse impact on our stock price and our business.

If the merger is not completed, or there are delays in completing the merger, our stock price and our business could be adversely affected and we would be subject to a number of risks, including the following:

• the current trading price of our common stock may reflect a market assumption that the merger will be completed and a failure to complete or delays in completing the merger could result in a decline in the price of our common stock;

• we may not realize the benefits expected from the merger, including cost savings, enhanced financial and competitive position and diversification of customer base, operating locations and assets;

• we will be required to pay certain costs relating to the merger, including certain investment banking, financing, legal and accounting fees and expenses, whether or not the merger is completed, and we may be required to pay Ensco a termination fee of $260 million under certain circumstances; and

• the merger agreement places certain restrictions on the conduct of our business prior to completion of the merger or termination of the merger agreement, and such restrictions may prevent us from making certain acquisitions or taking certain other specified actions during the pendency of the merger.

There can be no assurance that these risks will not materialize, and if any of them do, they may have an adverse effect on our financial position, results of operations and cash flows.

The merger may cause substantial disruption to our business, cause distraction to our management and employees and present difficulties retaining employees.

The merger may cause substantial disruption to our business, cause distraction to our management and employees and present difficulties retaining employees. The merger may also cause uncertainty to our customers. Matters related to the merger may require substantial commitments of time and resources and distract our management and employees from day-to-day operations. These disruptions could have an adverse effect on our financial position, results of operations and cash flows. In addition, uncertainty among our employees may have an adverse effect on us. This uncertainty may impair our ability to retain or attract personnel until the merger is completed. Employee retention may be particularly challenging, as employees may experience uncertainty about their future roles with the combined company.

The merger agreement restricts our ability to pursue alternatives to the merger.

The merger agreement contains provisions that, subject to limited fiduciary exceptions, restrict us or any of our employees from soliciting alternative acquisition proposals or offers for a competing transaction. Further, the requirement that we pay a termination fee of $260 million in specified circumstances and the requirement that we submit the adoption of the merger agreement to a vote of our stockholders even if our board of directors changes its recommendation in favor of the adoption of the merger agreement may discourage a third party that has an interest in acquiring all of or a significant part of our business from considering or proposing such acquisition, even if such party were prepared to pay higher consideration than the currently proposed merger consideration.

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Risk Factors About Our Spin-Off of Seahawk Drilling

Seahawk’s pending bankruptcy proceeding may result in claims against us, the reduction or elimination of amounts owed to us by Seahawk, and termination of our rights to make indemnification claims against Seahawk.

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. In February 2011, Seahawk and several of its affiliates filed for protection under Chapter 11 of the Bankruptcy Code. In the bankruptcy filings, we were listed as Seahawk’s largest unsecured creditor with a contingent, disputed, and unliquidated claim in the amount of approximately $16 million. The debt was listed as a trade payable, subject to setoff. The Seahawk debtors filed motions to sell substantially all of their assets and to obtain debtor-in-possession financing. The purchaser in the asset sale is proposed to be Hercules Offshore, Inc. and its affiliate SD Drilling LLC, which will pay base aggregate consideration consisting of approximately $25 million in cash and 22,321,425 shares of Hercules common stock. Prior to the commencement of the bankruptcy, Seahawk indicated an intention to seek, among other things, (i) to reject its outstanding contracts with us, thereby replacing Seahawk’s future performance obligations under the contracts with general unsecured claims in the bankruptcy, (ii) to seek a judicial determination or estimation of all of our claims against Seahawk, including indemnity claims and contract damage claims, and (iii) to set off claims Seahawk alleges it is owed for spin-off transition and other matters against all amounts currently payable from Seahawk to us in respect of transition services and rig management services, and to seek to recover any positive balance after such netting. In addition, the bankruptcy laws permit a debtor in bankruptcy, under certain circumstances, to challenge pre-bankruptcy payments or transfers of the debtor’s assets if the debtor received less than reasonably equivalent value while insolvent, or if the transfers were made with the actual intent to hinder, delay or defraud a creditor, or were made while insolvent on account of a pre-existing debt that has the effect of preferring the transferee over the debtor’s other creditors during the so-called preference period. Authorized representatives of the bankruptcy estate could seek to challenge transactions effected in connection with the spin-off under the bankruptcy laws.

In 2006, 2007 and 2009, Seahawk received tax assessments from the Mexican government related to the operations of certain of its subsidiaries. Pursuant to local statutory requirements, Seahawk has provided and may provide additional surety bonds, letters of credit, or other suitable collateral to contest these assessments. Pursuant to a tax support agreement between us and Seahawk, we agreed, at Seahawk’s request, to guarantee or indemnify the issuer of any such surety bonds, letters of credit, or other collateral issued for Seahawk’s account in respect of such Mexican tax assessments made prior to the spin-off date. On September 15, 2010, Seahawk requested that we provide credit support for four letters of credit issued for the appeals of four of Seahawk’s tax assessments. The amount of the request totaled approximately $48.4 million, based on exchange rates as of December 31, 2010. On October 28, 2010, we provided credit support in satisfaction of this request. Pursuant to the tax support agreement, Seahawk is required to pay us a fee based on the actual credit support provided. Seahawk’s quarterly fee payment due on December 31, 2010 was not made, which had the effect of terminating our obligation to provide further credit support under the tax support agreement. Further, on February 9, 2011, we sent a notice to Seahawk requesting that they provide cash collateral for the credit support that we previously provided on their behalf, as provided under the terms of the agreement. In connection with its bankruptcy filing, Seahawk is seeking to terminate its reimbursement obligations under the tax support agreement.

If certain of Seahawk’s claims and requests were granted, the adverse effect on us could be material. We cannot currently predict what actions may be taken by the bankruptcy court or other creditors or stakeholders of Seahawk in connection with the proceeding, or the effect the actions may have on our results of operations, financial condition or cash flows.

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 or the proposed purchase of Seahawk’s assets in its pending bankruptcy proceeding.

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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 3 and 4 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 12 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report.

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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 14, 2011, there were approximately 1,040 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
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
2010
First Quarter	$	34.36	$	27.12
Second Quarter		33.52		21.51
Third Quarter		30.45		21.62
Fourth Quarter		33.72		29.31

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

The following table presents information regarding our repurchases of shares of our common stock on a monthly basis during the fourth quarter of 2010:

					Total
					Number of		Maximum
					Shares		Number of
					Purchased as		Shares That
					Part of a		May Yet Be
	Total Number		Average		Publicly		Purchased
	of Shares		Price Paid		Announced		Under the
Period	Purchased (1)		Per Share		Plan(2)		Plan (2)
October 1-31, 2010		353	$	30.32		N/A		N/A
November 1-30, 2010		—		—		N/A		N/A
December 1-31, 2010		4,138	$	31.64		N/A		N/A
Total		4,491	$	31.54		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, 2010 and 2009, and for the years ended December 31, 2010, 2009 and 2008, 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, 2008, 2007 and 2006 and for the years ended December 31, 2007 and 2006 from consolidated financial information included in prior annual reports on Form 10-K. We have previously reclassified the historical results of operations of our former Latin America Land and E&P Services segments, three tender assist rigs, our former Eastern Hemisphere land rig operations, and our former 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,
	2010			2009			2008			2007			2006
	(In millions, except per share amounts)
Statement of Operations Data:
Revenues, excluding reimbursable revenues	$	1,431.5		$	1,563.5		$	1,664.7		$	1,294.2		$	885.9
Reimbursable revenues		28.6			30.7			37.9			34.8			22.7
Operating costs, excluding depreciation and amortization		871.9			828.3			766.5			618.6			587.9
Reimbursable costs		24.9			27.3			34.9			30.8			19.4
Depreciation and amortization		184.0			159.0			147.3			153.1			129.4
General and administrative, excluding depreciation and amortization		103.9			110.5			126.7			138.1			105.8
Department of Justice and Securities and Exchange Commission fines		—			56.2			—			—			—
Loss (gain) on sales of assets, net		0.2			(0.4	)		0.1			(29.8	)		(27.9	)
Earnings from operations		275.2			413.3			627.1			418.2			94.0
Interest expense, net of amounts capitalized		(13.4	)		(0.1	)		(20.0	)		(83.1	)		(89.0	)
Refinancing charges		(16.7	)		—			(2.3	)		—			—
Interest income		2.9			3.0			16.8			14.3			4.2
Other income (expense), net		4.0			(4.1	)		20.6			(2.7	)		2.5
Income from continuing operations before income taxes		252.0			412.1			642.2			346.7			11.7
Income taxes		(8.6	)		(71.8	)		(133.5	)		(86.9	)		(13.0	)
Income from continuing operations, net of tax	$	243.4		$	340.3		$	508.7		$	259.8		$	(1.3	)
Income from continuing operations per share:
Basic	$	1.37		$	1.93		$	2.95		$	1.54		$	(0.03	)
Diluted	$	1.37		$	1.92		$	2.89		$	1.51		$	(0.03	)
Shares used in per share calculations:
Basic		175.6			173.7			170.6			165.6			162.8
Diluted		176.2			174.0			175.2			178.1			162.8

	2010		2009		2008		2007		2006
	(In millions)
Balance Sheet Data:
Working capital	$	463.1	$	661.8	$	849.6	$	888.0	$	293.1
Property and equipment, net		5,961.2		4,890.3		4,592.9		4,021.4		4,000.3
Total assets		6,871.7		6,142.9		6,069.0		5,615.6		5,097.6
Long-term debt, net of current portion		1,833.4		1,161.7		692.9		1,111.9		1,280.2
Stockholders’ equity		4,516.3		4,257.8		4,400.0		3,474.0		2,643.5

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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 Statements 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 18, 2011, we operated a fleet of 26 rigs, consisting of five deepwater drillships, 12 semisubmersible rigs, seven independent leg jackups and two managed deepwater drilling rigs. We also have two 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.

Our primary strategic focus is on ownership and operation of floating offshore rigs, particularly deepwater rigs. Although crude oil prices have declined from the record levels reached in mid-2008, they have maintained a trading range in excess of $60 per barrel since August 2009, averaging approximately $80 per barrel in 2010, with a high closing price per barrel of $91.48 in December 2010. The market for deepwater drilling services remains uncertain in the near term, due especially to continued concern stemming from the global recession and the moratorium on offshore drilling in the U.S. Gulf of Mexico in 2010. However, we believe the long-term prospects for deepwater drilling are positive given 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, including enhanced reservoir recovery techniques. Since 2005, we have invested or committed to invest over $4.4 billion in the expansion of our deepwater fleet, including five new ultra-deepwater drillships, three of which were delivered in the first and third quarters of 2010 and the first quarter of 2011, and two of which are under construction with expected delivery dates in the fourth quarter of 2011 and third quarter of 2013. The three new drillships that have been delivered have multi-year contracts at favorable rates. Since 2005, we also have disposed of non-core assets, generating $1.6 billion in proceeds, enabling us to focus increasingly our financial and human capital on deepwater drilling.

With the tendency for deepwater drilling programs to be more insulated from short-term commodity price fluctuations, we expect that the deepwater market will outperform other offshore drilling market sectors over the long term. In addition, an increasing focus on deepwater prospects by national oil companies, whose exploration and production spending is less sensitive to general economic factors, serve to provide further stability in the deepwater sector. However, the Macondo well incident and its consequences, as discussed further below, have increased the near-term uncertainty in the sector. Our contract backlog at December 31, 2010 totaled $6.4 billion and was comprised primarily of contracts for our deepwater rigs awarded by large integrated oil and national oil companies.

Recent Developments

Proposed Merger with Ensco

On February 6, 2011, we entered into a merger agreement with Ensco plc and two of its subsidiaries. Pursuant to the merger agreement and subject to the conditions provided in the agreement, we will merge with one of the subsidiaries and become an indirect, wholly owned subsidiary of Ensco. The combination will create the industry’s second-largest offshore drilling fleet.

As a result of the merger, each outstanding share of our common stock (other than shares of our common stock held by Ensco, us or any of Ensco’s or our wholly owned subsidiaries (which will be cancelled as a result of the merger), those shares with respect to which appraisal rights under Delaware law are properly exercised and not withdrawn and other shares held by certain U.K. residents if determined by Ensco) will be converted into the right to receive $15.60 in cash and 0.4778 American depositary shares, representing Class A ordinary shares of Ensco. Under certain circumstances, UK residents may receive all cash consideration as a result of compliance with legal requirements.

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We have agreed to various covenants under the merger agreement and the closing of the transaction is subject to a number of conditions. Please read Note 17 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report for additional information about the terms of the transaction, our covenants under the merger agreement and the conditions to consummation of the transaction, as well as the financing commitments relating to the transaction. Please also read “Risk Factors” included in Item 1A. of Part I of this annual report for more information regarding risks relating to the transaction.

Drillships Construction Projects

On December 10, 2010, we entered into an agreement for the construction of a fifth new advanced-capability, ultra-deepwater drillship. The new drillship is based on a Samsung Heavy Industries proprietary hull design. The rig is designed for drilling in water depths of up to 12,000 feet, with a total vertical drilling depth of 40,000 feet. We believe the rig’s design and capabilities, which includes a dual derrick, will allow for numerous well construction and field development activities that can be performed in parallel, producing increased rig efficiencies. Following shipyard construction, commissioning and testing, the drillship is expected to be delivered to us at the shipyard in mid-2013. The agreement provides for an aggregate fixed purchase price of $544 million, subject to adjustment for delayed delivery, payable in installments during the construction process. We have the right to rescind the agreement for delays exceeding certain periods and for failure of the drillship to meet certain operating requirements or, alternatively, the right to liquidated damages for such delays or failures. We expect the total project cost, including commissioning and testing, to be approximately $600 million, excluding capitalized interest. The agreement also includes an option for a second unit at similar terms and conditions, which may be exercised by us during the first quarter of 2011.

In addition, we have an agreement for the construction of the ultra-deepwater drillship, the Deep Ocean Molokai. The Deep Ocean Molokai has a scheduled delivery date in the fourth quarter of 2011. Including amounts already paid and commissioning and testing, we expect total project cost to be approximately $790 million, excluding capitalized interest. Through December 31, 2010, we have spent approximately $295 million on this project. Although we currently do not have drilling contracts for the Deep Ocean Molokai or our fifth ultra-deepwater drillship, we expect that the long-term demand for deepwater drilling capacity in established and emerging basins should provide us with opportunities to contract these two rigs prior to their delivery dates.

There are risks of delay and cost overruns inherent in any major shipyard project, including those resulting from adverse weather conditions, work stoppages, disputes and financial and other difficulties encountered by the shipyard. In order to mitigate some of these risks, we have selected a high quality shipyard with a reputation for on-time completions. In addition, our construction contracts are based on a fixed fee, backed by a refund guarantee if the unit is ultimately not finished or accepted by us upon completion. Deliveries by the shipyard beyond a certain point in time are subject to penalty payments and cancellation. We also believe that constructing a drilling rig at a single shipyard presents a lower risk profile than projects that call for construction in multiple phases at separate shipyards, although some risks are more concentrated.

Recently Delivered Drillships

On January 24, 2011, we took delivery of our third new ultra-deepwater drillship, the Deep Ocean Mendocino. The Deep Ocean Mendocino is currently in transit to the U.S. Gulf of Mexico where it is expected to commence a five-year contract with a subsidiary of Petroleo Brasileiro S.A. (“Petrobras”) during the second quarter of 2011, following completion of integrated testing and acceptance by the client.

On February 28, 2010, we took delivery of the Deep Ocean Ascension, the first of our new ultra-deepwater drillships under construction. The drillship arrived in the U.S. Gulf of Mexico in May 2010 and has completed its acceptance testing with BP Exploration & Production Inc. (“BP E&P”). The rig was originally intended for drilling operations in the U.S. Gulf of Mexico. However, due to the moratorium on drilling in the U.S. Gulf of Mexico and more recently to regulatory changes that have created delays and uncertainty regarding the resumption of drilling in the U.S. Gulf of Mexico (discussed below under “—U.S. Gulf of Mexico”), BP E&P was unable to commence drilling operations with the Deep Ocean Ascension in the region according to its original schedule. In the third quarter of 2010, BP E&P agreed to place the Deep Ocean Ascension on a special standby dayrate of $360,000. The special standby dayrate is effective from August 23, 2010 until the earlier of April 1, 2011 or the date the rig begins mobilization to its first drilling site, either within or outside the U.S. Gulf of Mexico. The Deep Ocean Ascension is expected to mobilize to the Mediterranean Sea in the second quarter of 2011.

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On September 23, 2010, we took delivery of our second new ultra-deepwater drillship, the Deep Ocean Clarion. The drillship is currently in the process of finalizing the integrated acceptance testing program with BP E&P in the U.S. Gulf of Mexico, the originally intended location for drilling operations. Due to delays and uncertainty regarding the resumption of drilling in the U.S. Gulf of Mexico (discussed below under “—U.S. Gulf of Mexico”), in February 2011, BP E&P agreed to place the Deep Ocean Clarion on a special standby dayrate of $380,000 prior to the startup of the previously agreed five-year contract. The special standby dayrate will commence upon the earlier of completion of acceptance testing or March 1, 2011, and will continue until the earlier of the completion of certain customer requested modifications and upgrades or July 1, 2011. The Deep Ocean Clarion is expected to mobilize to a region outside of the U.S. Gulf of Mexico no later than July 1, 2011.

BP E&P owns a 65% working interest and is the operator of the exploration well associated with the Macondo well incident discussed below. While we currently expect BP E&P to perform its obligations under the drilling contracts for the Deep Ocean Ascension and the Deep Ocean Clarion, we cannot predict what actions BP E&P might attempt to take under the contracts or whether it ultimately will be able to perform its obligations in light of the incident and resulting spill. Our contracts with BP E&P do not include a written parent company guarantee. BP E&P may choose to exercise either contract’s termination for convenience clause, under which BP E&P would be required to provide a make-whole payment to us that approximates the present value of the cash margin that would have been earned over the life of the contract. If BP E&P fails to perform under the contracts, the drillships could be idle for an extended period of time. In that case, our revenues and profitability could be materially reduced if we are unable to secure new contracts on substantially similar terms, or at all.

Amendment of Revolving Credit Facility and Issuance and Redemption of Senior Notes

On July 30, 2010, we entered into an amended and restated unsecured revolving credit agreement with a group of banks that increased availability under the facility from $320 million to $720 million and extended the maturity from December 2011 to July 2013. On October 28, 2010, pursuant to the credit facility’s accordion feature, we increased the availability under the facility to $750 million.

On August 6, 2010, we completed an offering of $900 million aggregate principal amount of our 6 7/8% Senior Notes due 2020 and $300 million aggregate principal amount of our 7 7/8% Senior Notes due 2040. We used a portion of the net proceeds from the offering to redeem, on September 5, 2010, our entire outstanding $500 million aggregate principal amount of 7 3/8% Senior Notes due 2014 at a price of 102.458% of the principal amount, plus accrued and unpaid interest to the redemption date. We have used and expect to use the remainder of the net proceeds from the offering for general corporate purposes, which have included and may include payments with respect to our drillships under construction and other capital expenditures.

U.S. Gulf of Mexico

In response to the April 2010 Macondo well incident in the U.S. Gulf of Mexico, the Bureau of Ocean Energy Management, Regulation and Enforcement of the U.S. Department of the Interior (“BOEM”), at the time known as the Minerals Management Service, implemented a moratorium on certain drilling activities in the U.S. Gulf of Mexico until November 30, 2010. In October, 2010, the Secretary of the Interior directed the BOEM to lift the moratorium subject to certain specified conditions. During the pendency of the moratorium, the BOEM implemented various environmental, technological and safety measures intended to improve offshore safety systems and environmental protection. The newly issued safety regulations require operators to, among other things, submit independent third-party reports on the design and operation of blowout preventers (“BOPs”) and other well control systems, and conduct tests on the functionality of well control systems. Additional regulations address new standards for certain equipment involved in the construction of offshore wells, especially BOPs, and require operators to implement and enforce a safety and environmental management system including regular third-party audits of safety procedures and drilling equipment to insure that offshore rig personnel and equipment remain in compliance with the new regulations. Prior to the resumption of drilling following the moratorium, each operator is required to demonstrate that it has in place written and enforceable procedures, pursuant to applicable regulations, that ensure containment in the event of a deepwater blowout. We cannot currently predict the rate at which new well permits will be issued or the rate at which rigs will be allowed to return to work once compliance with the new regulations has been demonstrated. We believe, however, that the process followed by the BOEM to review and approve a well permit application by our clients will continue to be protracted relative to past experience, resulting in significant delays in the resumption of drilling in deepwater U.S. Gulf of Mexico that could persist through 2011.

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The U.S. Gulf of Mexico represents one of three established deepwater drilling basins in the world and currently accounts for more than 20% of the industry’s deepwater rig capacity. The region is a vital contributor to the economy in the United States, providing strong hydrocarbon production growth potential and significant employment opportunities. Despite the economic importance of the region, the deepwater drilling moratorium, and the significant delays in receiving drilling permits following the deepwater drilling moratorium and implementation of new regulations and offshore procedures, has created significant uncertainty regarding the outlook for the region and possible implications for regions outside of the U.S. Gulf of Mexico. Due to such uncertainty, some contract drillers and operators with floating rigs located in the region may choose to relocate the units to other international drilling areas. Through January 2011, five of the 33 floating rigs operating in the U.S. Gulf of Mexico at the time of the incident have secured new drilling assignments and have relocated or will relocate to international locations. Should there continue to be significant delays in the issuance of drilling permits or in allowing rigs to operate upon demonstration of compliance with new regulations or should additional regulations and government oversight, operating procedures and the possibility of increased legal liability be viewed by our clients as a significant impairment to expected economic returns on projects in the region, additional floating rigs could depart the U.S. Gulf of Mexico, with fewer clients operating in the region. As a result, a more challenging business environment could develop in the international sector, characterized by increased supply of rig capacity and declining dayrates.

In addition to the various environmental, technological and safety measures implemented during the pendency of the moratorium, we believe the U.S. government is likely to issue additional safety and environmental guidelines or regulations for drilling in the U.S. Gulf of Mexico and may take other steps that could delay operations, increase the cost of operations or reduce the area of operations for drilling rigs. Other governments could take similar actions. Additional governmental regulations concerning licensing, taxation, equipment specifications and crew training and competency requirements could increase the costs of our operations. Generally, we would seek to pass increased operating costs to our customers through cost escalation or change in law provisions in existing contracts or through higher dayrates on new contracts, where appropriate. Additionally, increased costs for our customers’ operations, along with permitting delays, could affect the economics of currently planned and future exploration and development activity, especially in the U.S. Gulf of Mexico, and reduce demand for our services. Furthermore, due to the Macondo well incident and resulting spill, insurance costs across the industry could increase, and certain insurance may be less available or not available at all, which could apply to our fleet.

The newly issued drilling equipment and safety requirements have imposed higher standards and could reduce the number of floating rigs capable of operating in the U.S. Gulf of Mexico. The operating limitation, if any, should be most evident in the industry’s lower specification units, which possess dated technology and operating equipment. We believe that the advanced technical features and equipment configuration already present in our five newbuild drillships will result in these units being substantially compliant with the newly issued safety requirements and would satisfy any new equipment specification guidelines without significant modifications, which could establish them as a preferred drilling asset by clients.

Except as described above under “— Recently Delivered Drillships” and below under “— Segment Review —Other Operations”, we do not currently have any rigs operating in the U.S. Gulf of Mexico.

Seahawk Spin-off and Subsequent Bankruptcy Filing

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.

In February 2011, Seahawk and several of its affiliates filed for protection under Chapter 11 of the Bankruptcy Code. In the bankruptcy filings, we were listed as Seahawk’s largest unsecured creditor with a contingent, disputed, and unliquidated claim in the amount of approximately $16 million. The debt was listed as a trade payable, subject to setoff. The Seahawk debtors filed motions to sell substantially all of their assets and to obtain debtor-in-possession financing. The purchaser in the asset sale is proposed to be Hercules Offshore, Inc. and its affiliate SD Drilling LLC, which will pay base aggregate consideration consisting of approximately $25 million in cash and 22,321,425 shares of Hercules common stock. Prior to the commencement of the bankruptcy, Seahawk indicated an intention to seek, among other things, (i) to reject its outstanding contracts with us, thereby replacing Seahawk’s future performance obligations under the contracts with general unsecured claims in the bankruptcy, (ii) to seek a judicial determination or estimation of all of our claims against Seahawk, including indemnity claims and contract damage claims, and (iii) to set off claims Seahawk alleges it is owed for spin-off transition and other matters against all amounts currently payable from Seahawk to us in respect of transition services and rig management services, and to seek to recover any positive balance after such netting. In addition, the bankruptcy laws permit a debtor in bankruptcy, under certain circumstances, to challenge pre-bankruptcy payments or transfers of the debtor’s assets if the debtor received less than reasonably equivalent value while insolvent, or if the transfers were made with the actual intent to hinder, delay or defraud a creditor, or were made while insolvent on account of a pre-existing debt that has the effect of preferring the transferee over the debtor’s other creditors during the so-called preference period. Authorized representatives of the bankruptcy estate could seek to challenge transactions effected in connection with the spin-off under the bankruptcy laws.

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In 2006, 2007 and 2009, Seahawk received tax assessments from the Mexican government related to the operations of certain of its subsidiaries. Pursuant to local statutory requirements, Seahawk has provided and may provide additional surety bonds, letters of credit, or other suitable collateral to contest these assessments. Pursuant to a tax support agreement between us and Seahawk, we agreed, at Seahawk’s request, to guarantee or indemnify the issuer of any such surety bonds, letters of credit, or other collateral issued for Seahawk’s account in respect of such Mexican tax assessments made prior to the spin-off date. On September 15, 2010, Seahawk requested that we provide credit support for four letters of credit issued for the appeals of four of Seahawk’s tax assessments. The amount of the request totaled approximately $48.4 million, based on exchange rates as of December 31, 2010. On October 28, 2010, we provided credit support in satisfaction of this request. Pursuant to the tax support agreement, Seahawk is required to pay us a fee based on the actual credit support provided. Seahawk’s quarterly fee payment due on December 31, 2010 was not made, which had the effect of terminating our obligation to provide further credit support under the tax support agreement. Further, on February 9, 2011, we sent a notice to Seahawk requesting that they provide cash collateral for the credit support that we previously provided on their behalf, as provided under the terms of the agreement. In connection with its bankruptcy filing, Seahawk is seeking to terminate its reimbursement obligations under the tax support agreement.

If certain of Seahawk’s claims and requests were granted, the adverse effect on us could be material. We cannot currently predict what actions may be taken by the bankruptcy court or other creditors or stakeholders of Seahawk in connection with the proceeding, or the effect the actions may have on our results of operations, financial condition or cash flows.

FCPA Investigation

We have resolved with the U.S. Department of Justice and the Securities and Exchange Commission our previously disclosed investigations into potential violations of the U.S. Foreign Corrupt Practices Act. In connection with the settlements, in the fourth quarter of 2010 we paid a total of $56.2 million in penalties, disgorgement and interest as described below. We had accrued this amount in the fourth quarter of 2009.

The settlement with the DOJ included a deferred prosecution agreement (“DPA”) between us and the DOJ and a guilty plea by our French subsidiary, Pride Forasol S.A.S., to FCPA-related charges. Under the DPA, the DOJ agreed to defer the prosecution of certain FCPA-related charges against us and agreed not to bring any further criminal or civil charges against us or any of our subsidiaries related to either any of the conduct set forth in the statement of facts attached to the DPA or any other information we disclosed to the DOJ prior to the execution of the DPA. We agreed, among other things, to continue to cooperate with the DOJ, to continue to review and maintain our anti-bribery compliance program and to submit to the DOJ three annual written reports regarding our progress and experience in maintaining and, as appropriate, enhancing our compliance policies and procedures. If we comply with the terms of the DPA, the deferred charges against us will be dismissed with prejudice. If, during the term of the DPA, the DOJ determines that we have committed a felony under federal law, provided deliberately false information or otherwise breached the DPA, we could be subject to prosecution and penalties for any criminal violation of which the DOJ has knowledge, including the deferred charges.

In December 2010, pursuant to a plea agreement, Pride Forasol S.A.S. pled guilty in U.S. District Court to conspiracy and FCPA charges. Pride Forasol S.A.S. was sentenced to pay a criminal fine of $32.6 million and to serve a three-year term of organizational probation.

The SEC investigation was resolved in November 2010. Without admitting or denying the allegations in a civil complaint filed by the SEC, we consented to the entry of a final judgment ordering disgorgement plus pre-judgment interest totaling $23.6 million and a permanent injunction against future violations of the FCPA.

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We have received preliminary inquiries from governmental authorities of certain of the countries referenced in our settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other 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. At this early stage of such inquiries, we are unable to determine what, if any, legal liability may result. 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 and derivative cases with respect to these matters, please see the discussion under “—Demand Letter and Derivative Cases” in Note 12 of the Notes to Consolidated Financial Statements included in Item 8 of this annual report. In addition, disclosure of the subject matter of the investigations and settlements 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. 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.

We cannot currently predict what, if any, actions may be taken by 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.

In addition, in connection with the investigation, our former Chief Operating Officer resigned as an officer effective May 31, 2006 and remained in the capacity of an employee to assist us with the investigation and to be available for consultation and to answer questions relating to our business. He had agreed to retire upon the conclusion of the investigation, and his right to receive retirement benefits was subject to the determination by our board of directors that we did not have cause (as defined in his retirement agreement with us) to terminate his employment. The board of directors recently determined that we did not have requisite cause to terminate his employment and that his retirement date was December 31, 2010.

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 records and 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 various regions, 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, permitting 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.

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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 received prior to commencement of the drilling contract are deferred and recognized as revenue over the term of the drilling contract.

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 drillships and semisubmersible 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 Jackup, which consists of our jackup rigs capable of operating in water depths up to 300 feet. We also manage the drilling operations for two deepwater drilling and production units owned by two clients, 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 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 criteria 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. Following an increase in 2009, labor costs continued to increase in 2010, especially for skilled personnel in certain geographic locations, such as Brazil, Angola and the United States. The increase in labor costs during 2010 was most pronounced in the Deepwater segment, and this increase in cost is expected to persist in 2011.

Beginning in 2005, the demand for contract drilling services increased significantly, 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 spare parts and other 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 spare parts in an effort to minimize unplanned downtime. With the decline in prices for steel and other key inputs that started in 2009 and the slow return in the level of business activity during 2010, we experienced some softening of lead times and pricing for spare parts and equipment during 2010.

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Crude oil prices have maintained a trading range in excess of $60 per barrel since August 2009 and averaged approximately $80 per barrel in 2010. Crude oil prices fell to $34 per barrel in February 2009 following the onset of the global financial crisis, deteriorating global economic fundamentals and the resulting drop in crude oil demand in a number of the world’s largest oil consuming nations. These factors had a negative impact on customer demand for offshore rigs throughout 2009, as evidenced by an estimated 15% decline in global exploration and production spending according to the Barclays Capital E&P Spending Survey. While the initial months of 2010 were characterized by a cautious pattern from many operators toward new exploration and production spending commitments similar to what was experienced in 2009, evidence was present that supported increased spending with a number of new drilling programs commencing in 2011 and beyond, largely supported by operators’ increasing confidence in the re-establishment of global economic growth and the sustainability of crude oil prices. However, following the April 2010 Macondo well incident and subsequent government actions, a new level of uncertainty among operators developed, with many choosing to delay the commencement of certain projects in the U.S. Gulf of Mexico and other regions pending further clarity on a number of industry issues. Worldwide offshore fleet utilization remained flat at approximately 73% at December 31, 2010 compared to 74% at December 31, 2009. Utilization for the industry’s deepwater fleet has historically been less sensitive to the extreme fluctuations experienced within the shallow water market even during market downturns. The timing of potentially higher spending patterns, especially in deepwater, is expected to remain uncertain until operators have gained more clarity concerning the long-term implications to our industry of the Macondo well incident, including an understanding of the impact of new operating regulations and government oversight. We believe that sustained oil prices above $60 per barrel since mid-2009 have contributed to increased confidence among operators and should lead to increased exploration and production spending, especially in international locations. However, operators will need to be confident in stronger oil market fundamentals supported by broadening global economic improvement, leading to increased crude oil demand, especially among member countries of the Organization for Economic Co-operation and Development.

We believe that long-term market conditions for offshore drilling services are supported by sound fundamental factors but that future demand for our rigs in the worldwide market is uncertain in the short-term due to the Macondo well incident in the U.S. Gulf of Mexico. We expect the long-term global demand for deepwater contract drilling services to be driven by growing worldwide demand for crude oil and natural gas as global populations expand and economic growth accelerates, along with 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, especially since the late-1990s, have led to numerous prolonged field development programs around the world, but especially in the U.S. Gulf of Mexico, Brazil and Angola. This success has contributed to the demand for a number of our deepwater assets by our clients through the next decade, especially those rigs that are capable of operating in water depths of 6,000 feet and greater and that possess advanced features, such as dynamic positioning, and well construction capabilities that offer increased drilling efficiencies. 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 long-term growing demand from clients for deepwater rigs. Following a record 25 deepwater discoveries in 2009, operators announced a record 31 deepwater discoveries in 2010 covering an expanding number of offshore basins, such as Ghana, the pre-salt formation offshore Brazil and Sierra Leone, further supporting the long-term sustainability of deepwater drilling demand. Announced discoveries in 2010 included discoveries along East Africa offshore Mozambique and Tanzania, representing the initial deepwater wells drilled offshore in this vast, emerging province. Additional exploration drilling opportunities offshore East Africa are expected to develop in the future with client interest expressed offshore Kenya and Madagascar. In addition, international oil companies are experiencing greater access to other promising areas offshore, such as India, Malaysia, Brunei, Australia, Sao Tomé, Príncipe, Liberia, Gabon, Greenland and the Black Sea. We anticipate that the combination of drilling successes, greater access to offshore basins, enhanced hydrocarbon recovery methods and continued advances in offshore drilling technology, which support increased efficiency in field development efforts like parallel drilling activities, will support the long-term outlook for deepwater rig demand. However, the possible increase in the international rig supply caused by new regulations and delays in the U.S. Gulf of Mexico could lead to an imbalance of supply, leading to a more challenging environment in the short-term.

Our deepwater fleet currently operates in Brazil, West Africa and the Mediterranean Sea. As described above under “— Recent Developments,” the Deep Ocean Ascension is currently in the U.S. Gulf of Mexico and has completed its acceptance testing and is currently on the special standby dayrate awaiting instructions from our client to commence mobilization to the Mediterranean Sea. We took delivery of the Deep Ocean Clarion in September 2010, and the rig arrived in the U.S. Gulf of Mexico in January 2011 where it is finalizing customer testing and acceptance. The rig will be placed on a special standby dayrate on or before March 1, 2011 prior to commencing its five-year contract with BP E&P, which is expected to be no later than July 1, 2011. In January 2011, we took delivery of the Deep Ocean Mendocino. The rig is currently in transit to the U.S. Gulf of Mexico where it is expected to commence a five-year contract with Petrobras during the second quarter of 2011, following customer testing and acceptance. Including rig days for our two remaining drillships currently under construction, based upon their scheduled delivery dates, we currently have 85% of our available rig days contracted for our deepwater fleet in 2011, with 75% in 2012, 60% in 2013 and 46% in 2014. Since an increase in customer demand for deepwater drilling rigs began in 2005, a high percentage of the industry’s deepwater fleet of 141 units accumulated large contract backlogs and remained under contract through 2010. This 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, contract awards for deepwater rigs equipped with dynamic positioning technology, capable of drilling in greater than 7,000 feet of water and available in 2010 remained above $400,000 per day, with contract awards in early 2011 exceeding $450,000 per day. These dayrates have been supported by strong geologic success, especially in Brazil, West Africa, the U.S. Gulf of Mexico and some of the new and emerging deepwater regions, which have led to a growing number of commercial discoveries.

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In Brazil, exploration drilling in the country’s prolific pre-salt formation has found numerous crude oil deposits of significant size residing more than 185 miles offshore and in up to 7,000 feet of water in the Santos Basin. Results of recent appraisal wells to define the potential size of these fields have confirmed the magnitude of the hydrocarbon complex. The successful drilling results in Brazil and aggressive exploration and development calendar have resulted in an announced exploration and production spending plan by Petrobras, the national oil company of Brazil, of over $200 billion from 2010 to 2014 to support development of the pre-salt formation and other global interests. The spending plan includes the need for 40 or more incremental deepwater rigs to be deployed in the numerous pre-salt fields discovered to date. Petrobras contracted 12 of the 40 rigs in 2008 from the international market and in February 2011 ordered seven rigs from a Brazilian shipyard with initial deliveries expected by 2015. Petrobras could order additional rigs from Brazilian shipyards or contract the needed rigs from the international rig market. Rigs obtained from the international rig market could represent additional demand in the short-term. In addition to the successful pre-salt geological trend in the Santos Basin offshore Brazil, a similar pre-salt geologic trend has been identified offshore West Africa, which could lead to increased deepwater drilling in that region over the coming years. In January 2011, Sonangol, the national oil company of Angola, began awarding offshore oil blocks residing in the country’s pre-salt trend, representing an initial step toward the exploration of this highly prospective area.

In addition, deepwater drilling economics have been aided in recent years by an expectation of higher average crude oil prices, supported by global population growth and 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 2017.

Industry uncertainty, due in part to the Macondo well incident and the U.S. government’s response, and its impact on our clients’ long-term planning horizons has resulted in some clients delaying decisions on deepwater drilling requirements. These delayed contracting decisions, together with limited charter of rig time between clients, have contributed to a decline in dayrates for deepwater rigs from levels experienced in 2008 as more units compete for a reduced number of contract opportunities. The lower utilization and dayrate decline are most pronounced among the conventionally moored deepwater semisubmersibles, which generally have the ability to operate in water depths of up to 6,000 feet and employ less sophisticated features. Dayrates for rigs of this technical specification, where eight units in the global fleet are currently idle, have weakened considerably from peak levels experienced during 2008 and could experience further weakness into 2011 as a growing number of rigs complete contracts. Dayrates for the industry’s technologically advanced deepwater rigs have also declined from the peak levels in 2008, including those possessing dynamic positioning technology and more efficient well construction features. However, due to operator preference for the advanced capabilities of these units, it is expected that utilization will remain high over the coming years, but dayrates could adjust lower in the near-term for several reasons, including continued delay by clients of the commencement of offshore programs, especially the large development programs that typically take multiple years to complete. Also, the increase in deepwater drilling capacity, particularly in 2011 and 2012 when as many as 12 uncommitted new deepwater rigs are expected to complete construction programs and enter the active global fleet, could place dayrates for these rigs under additional pressure. Many of the 12 uncommitted units are currently owned by new entrants to our business, possessing limited industry knowledge, global operational infrastructure and client relationships. We believe these attributes along with higher customer and regulatory standards are important considerations for our clients and will allow us to compete effectively for contract opportunities during this period of increased industry supply. However, we estimate that the Macondo well incident and resulting regulatory actions related to drilling in the U.S. Gulf of Mexico could continue to drive the relocation of a number of the deepwater rigs in the region to international locations, which would place dayrates and utilization for rigs in these locations under further pressure. As of December 31, 2010, six deepwater rigs in the U.S. Gulf of Mexico have relocated or have been identified for relocation to other regions with additional relocations possible.

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In 2011, new orders for 14 deepwater rigs have been placed by eight contractors with expected deliveries during 2013. The new orders, and our recent order for a fifth drillship placed in December 2010, are driven primarily by attractive pricing and payment terms offered by a number of shipyards and the increasingly favorable long-term outlook for the deepwater sector.

In light of the possible relocation of additional floating rigs out of the U.S. Gulf of Mexico, new deepwater rig capacity additions and increased availability of existing deepwater rigs as current contracts conclude over the next 12 months, dayrates and utilization for all deepwater rigs could have difficulty maintaining current levels until client demand begins to accelerate and there is an increase in multi-year field development projects. An encouraging indicator in the second half of 2010 and into the early months of 2011 was the existence of several contract awards, along with client tenders and inquiries for deepwater rigs with some project commencement dates in 2011. These projects are located in various areas, including the U.S. Gulf of Mexico, Angola and Brazil, where there is a building expectation that Petrobras will seek deepwater rig availability in the near-term to address its growing pre-salt development needs, as well as emerging regions along Africa, Europe and the Far East. Should this trend continue, we believe that the industry’s most sophisticated units could experience improvement during 2011 from the dayrate ranges experienced over most of 2010.

Our Midwater segment consists of six semisubmersible rigs. Five of the rigs currently operate offshore Brazil, with one rig, the Pride South Seas, cold stacked in South Africa. Recently, however, client interest in this rig has developed and, as a result, we are currently in the process of reactivating and marketing it to fill client needs in 2011. We currently have 77% of our available rig days contracted for our midwater fleet in 2011, with 35% in 2012, 14% in 2013 and none in 2014. Utilization of the industry’s midwater fleet was 80% at December 31, 2010, with 23 rigs idle around the world compared to utilization of 84% at the same time in 2009, when 18 rigs were idle. Economic instability and uncertainty in crude oil markets contributed to a growing number of inactive midwater rigs and this reduced level of activity was present through 2010, contributing to a more challenging dayrate environment. A modest increase in midwater activity during 2010 was most evident in Australia and in the U.K. and Norwegian sectors of the North Sea as these areas responded positively to improved prices for North Sea Brent crude oil, which averaged $84 per barrel in 2010, compared to $62 per barrel in 2009. A persistent weakness in the deepwater rig segment for conventionally moored deepwater rigs could result in additional pressure to Midwater segment utilization and dayrates in 2011, as 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, the number of midwater rigs located in the U.S. Gulf of Mexico has declined significantly over the past 10 years 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. We expect the worldwide supply of available midwater rigs to exceed client demand for the first half of 2011 with most contract opportunities characterized by short durations of six months or less.

Our Independent Leg Jackup segment, consisting of seven rigs, currently operates in the Middle East. We currently have 27% of our available rig days contracted for our independent leg jackup fleet in 2011, with 14% contracted in 2012 and 2013, and 1% in 2014. Four of our seven standard independent leg jackup rigs are currently without a contract, with limited prospects for work into the first half of 2011. Customer demand for jackup rigs declined steadily in 2010 while contract backlogs fell throughout the industry’s existing fleet of rigs and incremental capacity increased. As of December 31, 2010, 104 independent leg jackup rigs were idle in the global fleet out of a total fleet of 412, representing segment utilization of 75%. The addition of new jackup rig capacity in the industry represents a long-term threat to the segment, due in part to the geologic maturity of many shallow water drilling basins around the world, in contrast to the early stages of exploration and development characterized by most of the world’s deepwater basins. Since 2007, 88 jackup rigs have been added to the global fleet, with another 47 rigs expected to be added by the end of 2013. At December 31, 2010, 36 of the 47 expected incremental jackup rigs were without contracts. Despite the overall decline in jackup fleet utilization since 2009, customer demand for high specification units improved in 2010, with utilization of these rigs exceeding 90% and dayrates registering modest gains. These units possess advanced features, including greater hook loads, extended cantilever reach and the ability to drill wells with high pressure and temperature characteristics, such as those common in the UK and Norwegian sectors of the North Sea. Conversely, demand for the industry’s standard international-class jackup rigs, which possess dated features and technology, has declined significantly since 2009 and is expected to be flat through 2011.

We experienced approximately 730 out-of-service days for shipyard maintenance and upgrade projects for 2010 for our existing fleet as compared to approximately 660 days for 2009. The increase in out-of-service days in 2010 is primarily due to an increase of planned shipyard construction projects in our Independent Leg Jackup and Midwater segments partially offset by a reduction of planned projects in our Deepwater segment.

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Backlog

Our contracted backlog at December 31, 2010, totaled approximately $6.4 billion for our executed contracts. We expect approximately $1.6 billion of our total backlog to be realized in 2011. Our backlog at December 31, 2009 was approximately $6.9 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, 2010. 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 deepwater rigs under construction.

	For the Years Ending December 31,
	2011			2012			2013			2014
Rig Days Committed
Deepwater		85	%		75	%		60	%		46	%
Midwater		77	%		35	%		14	%		0	%
Independent Leg Jackups		27	%		14	%		14	%		1	%

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.

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.

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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 rigs 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 2010 and 2008, we extended the useful lives of certain of our rigs based on the results of our review of the useful lives of the rigs upon completion of shipyard projects. In 2010, this change resulted in a reduction in depreciation expense in 2010 of $4.3 million for continuing operations and increased after-tax diluted earnings per share from continuing operations by $0.02. In 2008, this change to the useful lives 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 2009, based on the results of our review of the useful lives of rigs that completed shipyard projects, we had no adjustments to the useful lives of the rigs.

We review our property and equipment for impairment when 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, 2010, 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.

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.

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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, 2010, we have net operating loss (“NOL”) carryforwards. With respect to essentially all of our foreign NOL carryforwards we have recognized a valuation allowance. Certain NOL carryforwards do not expire while others could expire starting in 2011 through 2030.

We have not provided for U.S. deferred taxes and related foreign dividend withholding taxes on approximately $2,235.9 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,
	2010			2009			2008
	(In millions)
Deepwater revenues:
Revenues, excluding reimbursables	$	916.3		$	810.3		$	874.6
Reimbursable revenues		14.2			12.8			7.6
Total Deepwater revenues		930.5			823.1			882.2
Midwater revenues:
Revenues, excluding reimbursables		365.8			412.9			419.5
Reimbursable revenues		1.7			6.5			6.0
Total Midwater revenues		367.5			419.4			425.5
Independent Leg Jackup revenues:
Revenues, excluding reimbursables		89.4			264.0			273.9
Reimbursable revenues		1.3			1.3			1.3
Total Independent Leg Jackup revenues		90.7			265.3			275.2
Other		70.9			83.0			119.2
Corporate		0.5			3.4			0.5
Total revenues	$	1,460.1		$	1,594.2		$	1,702.6
Earnings (loss) from continuing operations:
Deepwater	$	344.8		$	348.3		$	454.7
Midwater		66.5			129.0			163.6
Independent Leg Jackups		(25.1	)		105.4			133.2
Other		3.8			4.8			7.8
Corporate		(114.8	)		(174.2	)		(132.2	)
Total	$	275.2		$	413.3		$	627.1

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

	2010					2009					2008
	Average					Average					Average
	Daily		Utilization			Daily		Utilization			Daily		Utilization
	Revenues (1)		(2)			Revenues (1)		(2)			Revenues (1)		(2)
Deepwater	$	327,300		93	%	$	335,100		84	%	$	310,100		97	%
Midwater	$	261,000		64	%	$	258,700		74	%	$	249,400		78	%
Independent Leg Jackups	$	101,400		35	%	$	123,000		84	%	$	121,100		89	%

(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

2010 Compared with 2009

Revenues for our Deepwater segment increased $107.4 million, or 13%, for 2010 over 2009. The increase in revenues is primarily due to the Deep Ocean Ascension, which was placed on a special standby dayrate of $360,000 beginning in August 2010, the Pride North America, which operated at a higher dayrate in 2010, the Pride Brazil, which had higher utilization in 2010 due to time in the shipyard for contractual upgrades in the second quarter of 2009, the Pride Portland, which operated at a significantly higher dayrate for the majority of 2010 as compared to 2009, and the Pride Africa, which had higher utilization. These factors contributed to an increase in revenues of $132.5 million over 2009. However, results for 2010 were negatively affected by an on-going dispute with a client relating to the responsibility for payment of the time required for equipment inspection and maintenance at the specific request of the client on an unscheduled basis. As a result, we did not recognize an estimated $30 million of revenues relating to approximately 60 contracted rig days on the Pride North America due to the dispute pending resolution of the matter. The increase in revenues in 2010 was also partially offset by the Pride South Pacific, which, after completion of its upgrade, commenced a new contract mid-January 2010 at a substantially lower dayrate, and the Pride Angola, which experienced a decrease in days worked of 20 days in 2010 over 2009. Together, these factors resulted in a $25.8 million decrease in revenues in 2010 over 2009. Average daily revenues decreased 2% for 2010 over 2009 primarily due to the decreased dayrate for the Pride South Pacific and the impact of the disputed revenue for the Pride North America, partially offset by the commencement of the special standby dayrate of the Deep Ocean Ascension. Earnings from operations decreased $3.5 million, or 1%, for 2010 over 2009 due to the decline in earnings from the Pride South Pacific, start-up costs related to the Deep Ocean Ascension, the Deep Ocean Clarion and the Deep Ocean Mendocino, and an increase in labor costs for the offshore workforce. Utilization increased to 93% for 2010 as compared to 84% for 2009 primarily due to decreased out-of-service time experienced by the Pride South Pacific, Pride North America and Pride Portland, partially offset by the increased out-of-service time for the Pride Carlos Walter, which underwent a water depth upgrade and regulatory inspection in the first half of 2010, and the Pride Angola.

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.

Midwater

2010 Compared with 2009

Revenues for our Midwater segment decreased $51.9 million, or 12%, for 2010 over 2009. The decrease in revenues is primarily due to the Pride South Seas, which was idle for all of 2010, and the Pride Venezuela, which operated at a substantially lower dayrate in 2010, in addition to being in the shipyard for a rig refurbishment project in the first quarter of 2010 that was completed in the third quarter of 2010. These factors contributed to a decrease in revenues of $86.8 million over the comparable period in 2009. This decrease in revenues was partially offset by the Sea Explorer, which operated at a substantially higher dayrate in 2010 over 2009 and contributed an incremental $35.6 million in 2010 over 2009. Earnings from operations decreased $62.5 million, or 48%, for 2010 over 2009 primarily due to decreased revenues, which was largely attributable to the Pride South Seas, and increased labor costs, partially offset by incremental earnings associated with the higher dayrate and utilization of the Sea Explorer. Utilization decreased to 64% for 2010 from 74% for 2009 primarily due to the decreased utilization of the Pride South Seas, the Pride South America, and the Pride South Atlantic partially offset by the increased utilization of the Sea Explorer.

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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.

Independent Leg Jackup

2010 Compared with 2009

Revenues for our Independent Leg Jackup segment decreased $174.6 million, or 66%, for 2010 over 2009. The decrease in revenues is primarily due to the decreased utilization of our fleet resulting from a recent decline in the demand for shallow water rigs. The Pride Pennsylvania and the Pride Wisconsin remained stacked throughout 2010, and the Pride Tennessee was idle for the first quarter of 2010 and was then stacked for the remainder of the year. Additionally, the Pride Hawaii was idle for the majority of the second quarter of 2010 and the remainder of 2010, the Pride Cabinda experienced approximately 143 out-of-service days throughout 2010 while awaiting the commencement of new contracts, and the Pride Montana commenced a shipyard project in the first quarter of 2010 that was completed in the second quarter and resulted in 44 out-of-service days. These factors contributed to the decrease in revenues in 2010 compared to 2009, during which all of our rigs were substantially utilized. Average daily revenues decreased 18% for 2010 over 2009 primarily due to the Pride Cabinda, which operated at a significantly lower dayrate in 2010 over 2009. Earnings from operations decreased $130.5 million to a loss of $25.1 million for 2010 compared with earnings of $105.4 million for 2009 due to decreased revenues, primarily due to rigs that remained stacked or idle. Utilization decreased to 35% for 2010 from 84% for 2009, also primarily due to the rigs that remained stacked or idle during 2010.

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.

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Other Operations

Other operations include our deepwater drilling operations management contracts and other operating activities. Management contracts in 2010 include two contracts which currently expire in 2012 and 2015 (with early termination permitted in certain cases). Management contracts in 2009 also included one management contract that ended in the third quarter of 2009 and one management contract that ended in the fourth quarter of 2009. Management contracts in 2008 included two contracts that ended in the third and fourth quarters of 2008.

2010 Compared with 2009

Revenues decreased $12.1 million, or 15%, for 2010 over 2009 primarily due to the completion of two management contracts, in the third and fourth quarters of 2009, partially offset by increased revenue resulting from the commencement of a new management contract in April 2010 at a significantly higher dayrate. Earnings from operations decreased $1.0 million, or 21%, for 2010 over 2009 primarily due to the factors mentioned above.

2009 Compared with 2008

Revenues 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.

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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,
	2010			2009			2008
	(In millions)
REVENUES
Revenues, excluding reimbursable revenues	$	1,431.5		$	1,563.5		$	1,664.7
Reimbursable revenues		28.6			30.7			37.9
		1,460.1			1,594.2			1,702.6
COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		871.9			828.3			766.5
Reimbursable costs		24.9			27.3			34.9
Depreciation and amortization		184.0			159.0			147.3
General and administrative, excluding depreciation and amortization		103.9			110.5			126.7
Department of Justice and Securities and Exchange Commission fines		—			56.2			—
Loss (gain) on sales of assets, net		0.2			(0.4	)		0.1
		1,184.9			1,180.9			1,075.5
EARNINGS FROM OPERATIONS		275.2			413.3			627.1
OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		(13.4	)		(0.1	)		(20.0	)
Refinancing charges		(16.7	)		—			(2.3	)
Interest income		2.9			3.0			16.8
Other income (expense), net		4.0			(4.1	)		20.6
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		252.0			412.1			642.2
INCOME TAXES		(8.6	)		(71.8	)		(133.5	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX	$	243.4		$	340.3		$	508.7

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Revenues, Excluding Reimbursable Revenues. Revenues, excluding reimbursable revenues for 2010 decreased $132.0 million, or 8%, compared with 2009. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for 2010 decreased $2.1 million, or 7%, compared with 2009, primarily due to lower activity in our Midwater segment.

Operating Costs. Operating costs for 2010 increased $43.6 million, or 5%, compared with 2009. The increase is largely attributable to $52.0 million of increased startup and operating costs resulting from the Deep Ocean Ascension, which went on a special standby dayrate in August 2010, the Deep Ocean Clarion and Deep Ocean Mendocino. Additionally, within our Deepwater segment, excluding our newbuild drillships, we experienced an increase of $34.6 million in labor and materials and supplies costs. Partially offsetting these increases were reductions in operating costs totaling $45.8 million which resulted from lower activity in our Independent Leg Jackup segment.

Reimbursable Costs. Reimbursable costs for 2010 decreased $2.4 million, or 9%, compared with 2009 primarily due to lower activity within our Midwater and Independent Leg Jackup segments.

Depreciation and Amortization. Depreciation expense for 2010 increased $25.0 million, or 16%, compared with 2009. This increase relates to capital additions primarily in our Deepwater and Midwater segments, including the commencement of depreciation on the Deep Ocean Ascension in August 2010.

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General and Administrative. General and administrative expenses for 2010 decreased $6.6 million, or 6%, compared with 2009, primarily due to $5.7 million of lower labor costs and $1.3 million of lower expenses related to the investigation described under “—FCPA Investigation.”

Loss (Gain) on Sale of Assets, Net. We had net loss on sales of assets of $0.2 million for 2010 and a net gain of $0.4 million for 2009, primarily due to the sale of scrap equipment.

Interest Expense. Interest expense for 2010 increased $13.3 million compared with 2009, primarily due to the incremental interest associated with the issuance of additional long-term debt in 2009 and 2010, which was partially offset by the capitalization of interest, which totaled $102.5 million and $74.8 million for 2010 and 2009, respectively.

Refinancing Charges. Refinancing charges for 2010 were $16.7 million and primarily included a $12.3 million make-whole premium and $4.1 million write-off of unamortized debt discount and unamortized debt issuance costs upon redemption of our 7 3/8% Senior Notes due 2014 in September 2010. There were no refinancing charges for 2009.

Other Income (Expense), Net. Other income, net for 2010 increased $8.1 million to $4.0 million of income for 2010 from an expense of $4.1 million for 2009 primarily due to a $9.4 million favorable change in our foreign exchange gain (loss).

Income Taxes. Our consolidated effective income tax rate for continuing operations for 2010 was 3.4% compared with 17.4% for 2009. The lower tax rate for 2010 was principally the result of tax benefits related to the adjustment of intercompany pricing in the completion of our 2009 income tax return during the third quarter of 2010, lower income from continuing operations in 2010, and an increased proportion of income in lower tax jurisdictions in 2010.

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

Revenues, Excluding 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 $61.8 million, 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 were 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.

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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 ¹/2% 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.

Liquidity and Capital Resources

Our objective in financing our business is to maintain both adequate financial resources and access to additional liquidity. Our $750 million senior unsecured revolving credit facility provides back-up liquidity to meet our on-going working capital needs. Total long-term debt, including the current portion, at December 31, 2010 was $1.9 billion, and stockholders’ equity was $4.5 billion, resulting in a debt-to-total-capital ratio of 29%.

During 2010, we used cash on hand, cash flows generated from operations, and net proceeds from our August 2010 $1.2 billion senior notes offering as our primary source of liquidity for funding our working capital needs, debt repayment and capital expenditures. We believe that our cash on hand, including the remaining net proceeds from the August 2010 notes offering, cash flows from operations and availability under our revolving credit facility will provide sufficient liquidity through 2011 to fund our working capital needs and scheduled debt repayments. We expect to fund our remaining commitments under our drillship construction program using some combination of cash on hand, cash flow from operations and, if needed, borrowings under our revolving credit facility. 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.

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In December 2010, we reached a settlement with the DOJ and the SEC in connection with our liability under the FCPA. As part of the settlement, we made a cash payment in December 2010 totaling $56.2 million. For additional information regarding the settlement and our FCPA investigation, please read “—FCPA Investigation.”

Sources and Uses of Cash — 2010 Compared with 2009

Cash flows from operating activities

Cash flows from operating activities were $322.2 million for 2010 compared with $627.1 million for 2009. The decrease of $304.9 million was primarily due to a reduction of income from continuing operations and changes in operating assets and liabilities.

Cash flows used in investing activities

Cash flows used in investing activities were $1,251.9 million for 2010 compared with $1,059.8 million for 2009, an increase of $192.1 million. The increase is primarily attributable to an increase in expenditures incurred towards the construction of our ultra-deepwater drillships.

Cash flows from financing activities

Cash flows from financing activities were $651.6 million for 2010 compared with $483.3 million for 2009, an increase of $168.3 million. The increase in cash flows from financing activities was primarily due to the issuance in August 2010 of our 6 7/8% Senior Notes due 2020 and our 7 7/8% Notes due 2040, which resulted in net proceeds of $1.2 billion. We also redeemed our 7 3/8% Notes due 2014 at a price of 102.458% of the $500.0 million principal amount, plus accrued and unpaid interest to the redemption date, which resulted in total cash paid of $517.4 million. In June 2009, we issued our 8 1/2% Senior Notes due 2019, which resulted in net proceeds of $492.4 million. Cash used for scheduled debt repayments totaled $30.3 million for 2010 and 2009. We also received proceeds of $8.7 million and $20.1 million from employee stock transactions in 2010 and 2009, respectively.

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.

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.

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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 3¹/4% 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.

Working Capital

As of December 31, 2010, we had working capital of $463.1 million compared with $661.8 million as of December 31, 2009. The decrease in working capital is primarily due to expenditures of approximately $925 million incurred towards the construction of our ultra-deepwater drillships, partially offset by the net proceeds from the issuance of our 6 7/8% Senior Notes and our 7 7/8% Senior Notes and the redemption of our 7 3/8% Senior Notes in the third quarter of 2010.

Revolving Credit Facility

On July 30, 2010, we entered into an amended and restated unsecured revolving credit agreement with a group of banks that increased availability under the facility from $320 million to $720 million and extended the maturity from December 2011 to July 2013. On October 28, 2010, pursuant to the credit facility’s accordion feature, we increased the availability under the facility to $750 million. Amounts drawn under the credit facility are available in U.S. dollars or euros and bear interest at variable rates based on either LIBOR plus a margin that varies based on our credit rating or the alternative base rate as defined in the agreement.

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; hedging arrangements outside the ordinary course of business; and sale-leaseback transactions. The facility also requires us to maintain certain financial ratios. 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, 2010, there were no borrowings or letters of credit outstanding under the facility.

Other Outstanding Debt

As of December 31, 2010, 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;

• $900 million principal amount of 6 7/8% Senior Notes due 2020;

• $300 million principal amount of 7 7/8% Senior Notes due 2040; and

• $167 million principal amount of notes guaranteed by the United States Maritime Administration.

On August 6, 2010, we completed an offering of $900 million aggregate principal amount of our 6 7/8% Senior Notes due 2020 and $300 million aggregate principal amount of our 7 7/8% Senior Notes due 2040. The 2020 notes and the 2040 notes bear interest at 6.875% and 7.875%, respectively, 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. Upon a specified change in control event that results in a ratings decline, we will be required to make an offer to repurchase the notes at a repurchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest through the applicable repurchase date. The notes of each series are subject to redemption, in whole at any time or in part from time to time, at our option, 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.

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On September 5, 2010, we redeemed all of our outstanding 7 3/8% Senior Notes due 2014 with a portion of the proceeds from the issuance of the 2020 notes and 2040 notes. The aggregate principal amount of the 2014 notes of $500 million was redeemed at a price of 102.458% of the principal amount, plus accrued and unpaid interest to the redemption date.

We have used and expect to use the remaining proceeds from the offering of the 2020 notes and the 2040 notes, net of issuance costs, for general corporate purposes, which have included and may include payments with respect to our drillships under construction and other capital expenditures.

Our 8 1/2% Senior Notes due 2019 also 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.

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, 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 2011, excluding our commitments related to our drillship construction projects, to be approximately $265 million. These purchases have been and are expected to be used primarily for various rig upgrades in connection with new contracts as contracts expire during the year, the re-activation of rigs which were previously taken out of service, along with other sustaining capital projects. With respect to our drillship construction projects, which are scheduled to be completed in 2011 and 2013, the total remaining costs are estimated to be approximately $1.3 billion, which includes final payments totaling approximately $275 million on the recently delivered Deep Ocean Mendocino. These costs exclude rig mobilization costs, capital spares and other start-up costs. We expect to fund our remaining commitments under our newbuild program using some combination of cash on hand, including the net proceeds from our notes offering in August 2010, cash flow from operations, and, if needed, borrowings under our revolving credit facility.

We anticipate making income tax payments of approximately $47 million to $52 million in 2011.

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.

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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.

During the fourth quarter of 2010, we initiated a plan to open a regional headquarter for the Eastern hemisphere in the Netherlands and a project to consolidate our offices in France, in order to reduce costs and improve operating efficiencies. The restructuring effort contemplates closing down one office and reducing the overall workforce in France. We expect the restructuring to be completed in the third quarter of 2011 and the associated costs to be paid using cash from operations. The costs to be incurred for the restructuring will be primarily related to payments to be made under ongoing and one-time termination benefit arrangements; however, the terms are subject to negotiations with, and the formal opinion of, a local labor committee.

In addition to the matters described in this “— Liquidity and Capital Resources” section, please read “— FCPA Investigation,” “— 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, 2010 in the aggregate amount of $544.8 million under certain performance, bid and custom bonds and letters of credit. As of December 31, 2010, we had not been required to make any collateral deposits with respect to these agreements.

Contractual Obligations

In the table below, we set forth our contractual obligations as of December 31, 2010. 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)	$	1,863.7	$	30.3	$	60.6	$	60.6	$	1,712.2
Other long-term liabilities(2)		0.5		0.5		—		—		—
	$	1,864.2	$	30.8	$	60.6	$	60.6	$	1,712.2
Unrecorded contractual obligations:
Interest payments on long-term debt(3)		1,712.6		137.0		265.9		260.6		1,049.1
Operating lease obligations(4)		41.9		9.7		13.2		8.8		10.2
Purchase obligations(5)		167.8		159.4		8.4
Drillship construction agreements(6)		1,151.4		657.2		494.2		—		—
	$	3,073.7	$	963.3	$	781.7	$	269.4	$	1,059.3
Total	$	4,937.9	$	994.1	$	842.3	$	330.0	$	2,771.5

(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, 2010.

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(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 $73.5 million in purchase obligations related to drillship construction projects.
(6)	Includes shipyard payments under drillship construction agreements for our drillship construction projects.

As of December 31, 2010, we have approximately $40.8 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.

Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-6”). The update amends FASB Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures, (“ASC Topic 820”) to require additional disclosures related to transfers between levels in the hierarchy of fair value measurements. ASU 2010-6 is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted ASU 2010-6 as of January 1, 2010. Because the update did not change how fair values are measured, the update did not have an effect on our consolidated financial position, results of operations or cash flows.

In April 2010, the FASB issued ASU 2010-12, Accounting for Certain Tax Effects of the 2010 Health Care Reform Acts. This update codifies an SEC Staff Announcement relating to accounting for the Health Care and Education Reconciliation Act of 2010 and the Patient Protection and Affordable Care Act. We adopted ASU 2010-12 as of its effective date, April 14, 2010. The effect of the new health care laws on our consolidated financial position, results of operations and cash flows is immaterial.

In May 2010, the FASB issued ASU 2010-19, Foreign Currency Issues: Multiple Foreign Currency Exchange Rates. The purpose of this update is to codify the SEC Staff Announcement made at the March 18, 2010 meeting of the FASB Emerging Issues Task Force (“EITF”) by the SEC Observer to the EITF. The Staff Announcement provides the SEC staff’s view on certain foreign currency issues related to investments in Venezuela. ASU 2010-19 is effective as of March 18, 2010. We adopted the update as of its effective date. The update had no effect on our consolidated financial position, results of operations or cash flows.

In August 2010, the FASB issued ASU 2010-21, Accounting for Technical Amendments to Various SEC Rules and Schedules—Amendments to SEC Paragraphs Pursuant to Release No. 33-9026: Technical Amendments to Rules, Forms, Schedules and Codification of Financial Reporting Policies. This ASU amends various SEC paragraphs in the ASC to reflect changes made by the SEC in Final Rulemaking Release No. 33-9026, which was issued in April 2009 and amended SEC requirements in Regulation S-X and Regulation S-K and made changes to financial reporting requirements in response to the FASB’s issuance of Statement of Financial Accounting Standards (“SFAS”) No. 141(R), Business Combinations (FASB ASC Topic 805), and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (FASB ASC Topic 810). ASU 2010-21 is effective upon issuance. We adopted this update on its effective date. The update had no effect on our consolidated financial position, results of operations or cash flows. We previously adopted the guidance originally issued in SFAS 141(R) and SFAS 160 on January 1, 2009.

In August 2010, the FASB issued ASU 2010-22, Accounting for Various Topics—Technical Corrections to SEC Paragraphs. This update amends some of the SEC material in the ASC based on the June 2009 publication of Staff Accounting Bulletin (“SAB”) No. 112, which amended Topic 2, Topic 5, and Topic 6 in the SEC’s Staff Accounting Bulletin series. SAB 112 was issued to bring the SEC’s staff interpretative guidance into alignment with the changes in U.S. GAAP made in SFAS No. 141(R), Business Combinations (FASB ASC Topic 805), and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (FASB ASC Topic 810). ASU 2010-22 is effective upon issuance. We adopted this update on its effective date. The update had no effect on our consolidated financial position, results of operations or cash flows.

52

In December 2010, the FASB has issued ASU 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations. ASC Topic 805, Business Combinations, requires a public entity involved in a merger or acquisition to disclose pro forma information of the combined entity for business combinations that occur in the current reporting period. This update clarifies the acquisition date that should be used for reporting the pro forma financial information disclosures in ASC Topic 805 when comparative financial statements are presented. The update requires the pro forma information for business combinations to be presented as if the business combination occurred at the beginning of the prior annual reporting period when calculating both the current reporting period and the prior reporting period pro forma financial information. The update also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination. The amended guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We adopted the update as of January 1, 2011. We do not expect the update to have a material effect on our consolidated financial position, results of operations or cash flows.

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;

• the satisfaction of closing conditions to the merger agreement with Ensco plc and the completion of the proposed merger, as well as Ensco’s ability to obtain adequate financing to fund the merger consideration;

• the Macondo well incident in the U.S. Gulf of Mexico in April 2010 and its consequences, including actions that may be taken by the U.S. government, other governments or our customers;

• 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;

• 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 or future insurance coverage and indemnification from our customers under our drilling contracts;

• expected outcomes of legal, tax and administrative proceedings 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.

53

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;

• 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, including acceptance testing 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.

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, 2010 and 2009 was $2,030.2 million and $1,307.6 million, respectively, which was more than its carrying value as of December 31, 2010 and 2009 of $1,863.7 and $1,192.0 million, respectively. A hypothetical 100 basis point decrease in interest rates relative to market interest rates at December 31, 2010 would increase the fair market value of our long-term debt at December 31, 2010 by approximately $143.5 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, 2010 and 2009, we had contracts outstanding to exchange an aggregate $5.8 million and $6.0 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, 2010 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.

54

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, 2010 and 2009, 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, 2010. 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, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010, 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, 2010, 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 18, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas
February 18, 2011

55

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, 2010, 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. 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, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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, 2010 and 2009, 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, 2010, and our report dated February 18, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas
February 18, 2011

56

Pride International, Inc.

Consolidated Balance Sheets

(In millions, except par value)

	December 31,
	2010			2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	485.0		$	763.1
Trade receivables, net		200.3			211.9
Deferred income taxes		10.1			21.6
Other current assets		127.3			167.6
Total current assets		822.7			1,164.2
PROPERTY AND EQUIPMENT		7,337.0			6,091.0
Less: accumulated depreciation		1,375.8			1,200.7
Property and equipment, net		5,961.2			4,890.3
OTHER ASSETS, NET		87.8			88.4
Total assets	$	6,871.7		$	6,142.9
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	30.3		$	30.3
Accounts payable		112.3			132.4
Accrued expenses and other current liabilities		217.0			339.7
Total current liabilities		359.6			502.4
OTHER LONG-TERM LIABILITIES		101.5			118.3
LONG-TERM DEBT, NET OF CURRENT PORTION		1,833.4			1,161.7
DEFERRED INCOME TAXES		60.9			102.7
STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value; 50.0 shares authorized; none issued		—			—
Common stock, $0.01 par value; 400.0 shares authorized; 176.9 and 175.5 shares issued; 175.8 and 174.6 shares outstanding		1.8			1.8
Paid-in capital		2,103.0			2,058.7
Treasury stock, at cost; 1.1 and 0.9 shares		(21.8	)		(16.4	)
Retained earnings		2,429.9			2,210.8
Accumulated other comprehensive income		3.4			2.9
Total stockholders’ equity		4,516.3			4,257.8
Total liabilities and stockholders’ equity	$	6,871.7		$	6,142.9

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

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Pride International, Inc.

Consolidated Statements of Operations

(In millions, except per share amounts)

	Year Ended December 31,
	2010			2009			2008
REVENUES
Revenues, excluding reimbursable revenues	$	1,431.5		$	1,563.5		$	1,664.7
Reimbursable revenues		28.6			30.7			37.9
		1,460.1			1,594.2			1,702.6
COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		871.9			828.3			766.5
Reimbursable costs		24.9			27.3			34.9
Depreciation and amortization		184.0			159.0			147.3
General and administrative, excluding depreciation and amortization		103.9			110.5			126.7
Department of Justice and Securities and Exchange Commission fines		—			56.2			—
Loss (gain) on sales of assets, net		0.2			(0.4	)		0.1
		1,184.9			1,180.9			1,075.5
EARNINGS FROM OPERATIONS		275.2			413.3			627.1
OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		(13.4	)		(0.1	)		(20.0	)
Refinancing charges		(16.7	)		—			(2.3	)
Interest income		2.9			3.0			16.8
Other income (expense), net		4.0			(4.1	)		20.6
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		252.0			412.1			642.2
INCOME TAXES		(8.6	)		(71.8	)		(133.5	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX		243.4			340.3			508.7
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX		(24.3	)		(54.5	)		342.4
NET INCOME	$	219.1		$	285.8		$	851.1
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	1.37		$	1.93		$	2.95
Income (loss) from discontinued operations		(0.14	)		(0.31	)		1.99
Net income	$	1.23		$	1.62		$	4.94
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	1.37		$	1.92		$	2.89
Income (loss) from discontinued operations		(0.14	)		(0.31	)		1.94
Net income	$	1.23		$	1.61		$	4.83
SHARES USED IN PER SHARE CALCULATIONS
Basic		175.6			173.7			170.6
Diluted		176.2			174.0			175.2

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

58

Pride International, Inc.

Consolidated Statements of Stockholders’ Equity

(In millions)

																Accumulated
																Other			Total
	Common Stock				Paid-in			Treasury Stock					Retained			Comprehensive			Stockholders’
	Shares		Amount		Capital			Shares		Amount			Earnings			Income (Loss)			Equity
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 of tax
Net income														851.1						851.1
Foreign currency translation																	(6.0	)		(6.0	)
Foreign currency hedges																	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 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 of tax
Net income														285.8						285.8
Foreign currency translation																	2.4			2.4
Foreign currency hedges																	(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 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
Comprehensive income, net of tax
Net income														219.1						219.1
Foreign currency translation																	2.2			2.2
Foreign currency hedges																	0.1			0.1
Change in defined benefit plan funded status																	(1.8	)		(1.8	)
Total comprehensive income														219.1			0.5			219.6
Exercise of stock options		0.3				5.2														5.2
Tax benefit from stock-based compensation						2.8														2.8
Stock-based compensation, net		1.1				36.3			0.2		(5.4	)								30.9
Balance, December 31, 2010		176.9	$	1.8	$	2,103.0			1.1	$	(21.8	)	$	2,429.9		$	3.4		$	4,516.3

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

59

Pride International, Inc.

Consolidated Statements of Cash Flows

(In millions)

	Year Ended December 31,
	2010			2009			2008
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	219.1		$	285.8		$	851.1
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	)
Gain on sale of equity method investment		—			—			(11.4	)
Depreciation and amortization		184.0			196.5			210.8
Refinancing charges		12.3			—			—
Amortization and write-offs of deferred financing costs		6.1			2.4			5.2
Amortization of deferred contract liabilities		(45.8	)		(53.8	)		(59.0	)
Impairment charges		—			33.4			—
Gain on sales of assets, net		(0.1	)		(0.4	)		(24.0	)
Deferred income taxes		(27.8	)		(13.2	)		78.1
Excess tax benefits from stock-based compensation		(2.8	)		(1.5	)		(7.7	)
Stock-based compensation		32.7			35.9			24.8
Other, net		2.2			0.9			2.2
Net effect of changes in operating accounts (See Note 15)		(39.4	)		142.8			(26.9	)
Change in deferred gain on asset sales and retirements		—			4.9			(12.3	)
Increase (decrease) in deferred revenue		(9.6	)		13.8			(8.7	)
Decrease (increase) in deferred expense		(8.7	)		(15.0	)		6.3
NET CASH FLOWS FROM OPERATING ACTIVITIES		322.2			627.1			844.1
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Purchases of property and equipment		(1,253.3	)		(994.4	)		(984.0	)
Reduction of cash from spin-off of Seahawk		—			(82.4	)		—
Proceeds from dispositions of property and equipment		1.4			7.4			65.8
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 insurance		—			—			25.0
NET CASH FLOWS USED IN INVESTING ACTIVITIES		(1,251.9	)		(1,059.8	)		(582.5	)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Repayments of borrowings		(542.6	)		(30.3	)		(537.2	)
Proceeds from debt borrowings		1,200.0			498.2			68.0
Debt finance costs		(17.3	)		(6.2	)		(2.7	)
Net proceeds from employee stock transactions		8.7			20.1			24.7
Excess tax benefits from stock-based compensation		2.8			1.5			7.7
NET CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES		651.6			483.3			(439.5	)
Increase (decrease) in cash and cash equivalents		(278.1	)		50.6			(177.9	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		763.1			712.5			890.4
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	485.0		$	763.1		$	712.5

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

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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 26 offshore rigs. We also have two ultra-deepwater drillships under construction.

Basis of Presentation

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.

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. We evaluate our estimates and assumptions on a regular basis, including those related to revenue recognition, property and equipment, income taxes, stock-based compensation and contingencies. We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. 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 5).

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.

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.

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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. 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 years 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 rigs 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 2010 and 2008, we extended the useful lives of certain rigs based on the results of our review of the useful lives of the rigs upon completion of shipyard projects. In 2010, this change resulted in a reduction in depreciation expense in 2010 of $4.3 million for continuing operations and increased after-tax diluted earnings per share from continuing operations by $0.02. In 2008, this change to the useful lives 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 2009, based on the results of our review of the useful lives of rigs that completed shipyard projects, we had no adjustments to the useful lives of the rigs.

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 review our property and equipment for impairment when events or changes in circumstances indicate the carrying value of such assets or asset groups may not be recoverable, such as a significant decrease in market value of the assets or a significant change in the business conditions in a particular market. 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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During the first and second quarters of 2010, management determined that the current and forecasted operating losses of our independent leg jackup fleet represented a triggering event for the asset group. Management performed an undiscounted cash flow analysis for the group’s long-lived assets to determine if there was any impairment of the asset group and, as a result of this analysis, determined that no impairment was required.

Future changes that might occur in our Independent Leg Jackup asset group, such as the stacking of additional rigs, decreases in dayrates and declining utilization, might result in changes to our estimates and assumptions used in our undiscounted cash flow analysis. This could affect whether or not projected undiscounted cash flows continue to exceed the carrying value of the Independent Leg Jackup asset group and could result in a required impairment charge in a future period.

In connection with the spin-off of Seahawk Drilling, Inc. (“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, 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, 2010 and 2009, the deferred and unamortized portion of such costs on our balance sheet was $40.6 million and $31.4 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, 2010 and 2009, 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.

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 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.

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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. Our methodology for estimating expected volatility is based on a combination of historical volatility and peer group historical volatility. 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 is based on historical volatility of 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 appropriately 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.

Earnings per Share

We compute basic earnings per share from continuing operations based on the weighted average number of shares of common stock outstanding during the applicable period. We compute diluted earnings per share from continuing operations 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.

Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-6”). The update amends FASB Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures, (“ASC Topic 820”) to require additional disclosures related to transfers between levels in the hierarchy of fair value measurements. ASU 2010-6 is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted ASU 2010-6 as of January 1, 2010. Because the update did not change how fair values are measured, the update did not have an effect on our consolidated financial position, results of operations or cash flows.

In April 2010, the FASB issued ASU 2010-12, Accounting for Certain Tax Effects of the 2010 Health Care Reform Acts. This update codifies an SEC Staff Announcement relating to accounting for the Health Care and Education Reconciliation Act of 2010 and the Patient Protection and Affordable Care Act. We adopted ASU 2010-12 as of its effective date, April 14, 2010. The effect of the new health care laws on our consolidated financial position, results of operations and cash flows is immaterial.

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In May 2010, the FASB issued ASU 2010-19, Foreign Currency Issues: Multiple Foreign Currency Exchange Rates. The purpose of this update is to codify the SEC Staff Announcement made at the March 18, 2010 meeting of the FASB Emerging Issues Task Force (“EITF”) by the SEC Observer to the EITF. The Staff Announcement provides the SEC staff’s view on certain foreign currency issues related to investments in Venezuela. ASU 2010-19 is effective as of March 18, 2010. We adopted the update as of its effective date. The update had no effect on our consolidated financial position, results of operations or cash flows.

In August 2010, the FASB issued ASU 2010-21, Accounting for Technical Amendments to Various SEC Rules and Schedules—Amendments to SEC Paragraphs Pursuant to Release No. 33-9026: Technical Amendments to Rules, Forms, Schedules and Codification of Financial Reporting Policies. This ASU amends various SEC paragraphs in the ASC to reflect changes made by the SEC in Final Rulemaking Release No. 33-9026, which was issued in April 2009 and amended SEC requirements in Regulation S-X and Regulation S-K and made changes to financial reporting requirements in response to the FASB’s issuance of Statement of Financial Accounting Standards (“SFAS”) No. 141(R), Business Combinations (FASB ASC Topic 805), and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (FASB ASC Topic 810). ASU 2010-21 is effective upon issuance. We adopted this update on its effective date. The update had no effect on our consolidated financial position, results of operations or cash flows. We previously adopted the guidance originally issued in SFAS 141(R) and SFAS 160 on January 1, 2009.

In August 2010, the FASB issued ASU 2010-22, Accounting for Various Topics—Technical Corrections to SEC Paragraphs. This update amends some of the SEC material in the ASC based on the June 2009 publication of Staff Accounting Bulletin (“SAB”) No. 112, which amended Topic 2, Topic 5, and Topic 6 in the SEC’s Staff Accounting Bulletin series. SAB 112 was issued to bring the SEC’s staff interpretative guidance into alignment with the changes in U.S. GAAP made in SFAS No. 141(R), Business Combinations (FASB ASC Topic 805), and SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (FASB ASC Topic 810). ASU 2010-22 is effective upon issuance. We adopted this update on its effective date. The update had no effect on our consolidated financial position, results of operations or cash flows.

In December 2010, the FASB has issued ASU 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations. ASC Topic 805, Business Combinations, requires a public entity involved in a merger or acquisition to disclose pro forma information of the combined entity for business combinations that occur in the current reporting period. This update clarifies the acquisition date that should be used for reporting the pro forma financial information disclosures in ASC Topic 805 when comparative financial statements are presented. The update requires the pro forma information for business combinations to be presented as if the business combination occurred at the beginning of the prior annual reporting period when calculating both the current reporting period and the prior reporting period pro forma financial information. The update also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination. The amended guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We adopted the update as of January 1, 2011. We do not expect the update to have a material effect on our consolidated financial position, results of operations or cash flows.

Reclassifications

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

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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 comprising operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes from the rest of our operations. 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.

Seahawk Spin-off and Subsequent Bankruptcy Filing

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.

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

	2010			2009			2008
Revenues	$	—		$	189.4		$	607.9
Operating costs, excluding depreciation and amortization		3.7			161.6			326.6
Depreciation and amortization		—			37.5			59.2
General and administrative, excluding depreciation and amortization		0.8			34.3			3.9
Impairment expense		—			33.4			—
Gain on sales of assets, net		—			(5.0	)		(24.2	)
Earnings (loss) from operations	$	(4.5	)	$	(72.4	)	$	242.4
Other income (expense), net		—			2.6			(2.5	)
Income (loss) before taxes		(4.5	)		(69.8	)		239.9
Income taxes		(6.1	)		17.1			(83.2	)
Income (loss) from discontinued operations	$	(10.6	)	$	(52.7	)	$	156.7

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. During the third quarter of 2010, we recorded a charge to income tax expense for discontinued operations due to the allocation of additional foreign tax credits to Seahawk stemming from the finalization of our 2009 income tax return. During the fourth quarter of 2010, we recorded charges of $4.1 million and $2.3 million to discontinued operations and continuing operations, respectively, related to the establishment of an allowance for uncollectible receivables. As of December 31, 2010, we had a receivable from Seahawk of $16.0 million, net of allowance, which is included in “Other current assets,” pursuant to a transition services agreement and management agreements for the operation of the Pride Wisconsin and the Pride Tennessee in connection with the spin-off.

In February 2011, Seahawk and several of its affiliates filed for protection under Chapter 11 of the Bankruptcy Code. In the bankruptcy filings, we were listed as Seahawk’s largest unsecured creditor with a contingent, disputed, and unliquidated claim in the amount of approximately $16 million. The debt was listed as a trade payable, subject to setoff. The Seahawk debtors filed motions to sell substantially all of their assets and to obtain debtor-in-possession financing. The purchaser in the asset sale is proposed to be Hercules Offshore, Inc. and its affiliate SD Drilling LLC, which will pay base aggregate consideration consisting of approximately $25 million in cash and 22,321,425 shares of Hercules common stock. Prior to the commencement of the bankruptcy, Seahawk indicated an intention to seek, among other things, (i) to reject its outstanding contracts with us, thereby replacing Seahawk’s future performance obligations under the contracts with general unsecured claims in the bankruptcy, (ii) to seek a judicial determination or estimation of all of our claims against Seahawk, including indemnity claims and contract damage claims, and (iii) to set off claims Seahawk alleges it is owed for spin-off transition and other matters against all amounts currently payable from Seahawk to us in respect of transition services and rig management services, and to seek to recover any positive balance after such netting. In addition, the bankruptcy laws permit a debtor in bankruptcy, under certain circumstances, to challenge pre-bankruptcy payments or transfers of the debtor’s assets if the debtor received less than reasonably equivalent value while insolvent, or if the transfers were made with the actual intent to hinder, delay or defraud a creditor, or were made while insolvent on account of a pre-existing debt that has the effect of preferring the transferee over the debtor’s other creditors during the so-called preference period. Authorized representatives of the bankruptcy estate could seek to challenge transactions effected in connection with the spin-off under the bankruptcy laws.

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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:

	2010			2009			2008
Revenues	$	—		$	6.7		$	70.4
Income (loss) before taxes		(0.3	)		(1.0	)		8.6
Income taxes		(0.3	)		(2.0	)		(11.1	)
Gain on disposal of assets, net of tax		—			5.4			6.2
Income (loss) from discontinued operations	$	(0.6	)	$	2.4		$	3.7

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. In December 2009, we filed suit against the buyer in the federal district court in the Southern District of New York to collect the final amount of the working capital adjustment payable by the buyer to us, plus interest, as determined in accordance with the purchase agreement, and the buyer made various counterclaims in the proceeding. All claims of the parties were settled in the first quarter of 2010, and the federal district court dismissed the claims with prejudice on March 10, 2010. From the closing date of the sale in the third quarter of 2007 through December 31, 2010, we recorded a total gain on disposal of $318.6 million, which included certain 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 indemnified liabilities will be settled with the buyer in cash. Our total estimated gain on disposal of assets includes an $8.1 million liability, based on our fair value estimates for the indemnities, and a $6.7 million asset for the cash value of tax benefits related to tax overpayments that the buyer will owe us when the benefits are realized. In the first quarter of 2010, we recorded a $6.8 million charge to the gain on disposal in connection with the re-measurement of a remaining indemnity that resulted from a foreign exchange fluctuation. The expected settlement dates for the remaining tax indemnities may vary from within one year to several years. Our final gain may be materially affected by the final resolution of these matters.

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

	2010			2009			2008
Revenues	$	0.7		$	15.0		$	88.0
Income (loss) before taxes		(5.6	)		0.7			5.8
Income taxes		(0.4	)		(0.2	)		(2.0	)
Gain (loss) on disposal of assets, net of tax		(7.1	)		(4.7	)		178.2
Income (loss) from discontinued operations	$	(13.1	)	$	(4.2	)	$	182.0

NOTE 3. PROPERTY AND EQUIPMENT

Property and equipment consisted of the following at December 31:

	2010			2009
Rigs and rig equipment	$	5,256.1		$	4,101.4
Construction-in-progress — newbuild drillships		1,788.8			1,682.4
Construction-in-progress — other		204.8			222.8
Other		87.3			84.4
Property and equipment, cost		7,337.0			6,091.0
Accumulated depreciation and amortization		(1,375.8	)		(1,200.7	)
Property and equipment, net	$	5,961.2		$	4,890.3

Depreciation and amortization expense of property and equipment for 2010, 2009 and 2008 was $184.0 million, $159.0 million and $147.3 million, respectively.

During 2010, 2009 and 2008, maintenance and repair costs included in operating costs on the accompanying consolidated statements of operations were $117.1 million, $129.1 million and $112.1 million, respectively.

We capitalize interest applicable to the construction of significant additions to property and equipment. For 2010, 2009 and 2008, we capitalized interest of $102.5 million, $74.7 million and $41.2 million, respectively. For 2010, 2009 and 2008, total interest costs, including amortization of debt issuance costs, were $115.9 million, $74.8 million and $61.2 million, respectively.

Construction-in-progress — Newbuild Drillships

On February 28, 2010, we took delivery of the Deep Ocean Ascension, the first of our five new ultra-deepwater drillships. The rig is currently under contract in the U.S. Gulf of Mexico and is expected to mobilize to the Mediterranean Sea in the second quarter of 2011.

On September 23, 2010, we took delivery of our second new ultra-deepwater drillship, the Deep Ocean Clarion. The rig is currently completing acceptance testing in the U.S. Gulf of Mexico and is expected to commence its contract late in the first quarter of 2011.

On January 24, 2011, we took delivery of our third new ultra-deepwater drillship, the Deep Ocean Mendocino. The Deep Ocean Mendocino is currently in transit to the U.S. Gulf of Mexico where it is expected to commence its contract during the second quarter of 2011 following completion of acceptance testing.

On December 10, 2010, we entered into an agreement for the construction of a fifth advanced-capability, ultra-deepwater drillship. Following shipyard construction, commissioning and testing, the drillship is expected to be delivered to us at the shipyard in mid-2013. The agreement provides for an aggregate fixed purchase price of $544 million, subject to adjustment for delayed delivery, payable in installments during the construction process. We expect the total project cost, including commissioning and testing, to be approximately $600 million, excluding capitalized interest. The agreement also includes an option for a second unit at similar terms and conditions, which may be exercised by us during the first quarter of 2011.

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In addition, we have an agreement for the construction of the Deep Ocean Molokai, our fourth new ultra-deepwater drillship. The Deep Ocean Molokai has a scheduled delivery date in the fourth quarter of 2011.

Including amounts already paid and commissioning and testing, we expect total costs for our two remaining construction projects to be approximately $1.0 billion, excluding capitalized interest. Through December 31, 2010, we have spent approximately $345 million on these projects.

At December 31, 2010, our purchase obligations to the shipyard related to our three newbuild drillship construction projects as of such date, which includes the drillship delivered in January 2011, are as follows:

	Amount
2011	$	657.2
2012		108.8
2013		385.4
2014		—
2015		—
Thereafter		—
	$	1,151.4

NOTE 4. INDEBTEDNESS

Senior Unsecured Revolving Credit Facility

On July 30, 2010, we entered into an amended and restated unsecured revolving credit agreement with a group of banks that increased availability under the facility from $320.0 million to $720.0 million and extended the maturity from December 2011 to July 2013. As a result of this amendment, we recognized a charge of $0.3 million during the third quarter of 2010 related to the write-off of unamortized debt issuance costs associated with the previous facility, which is included in “Refinancing charges” for the year ended December 31, 2010. On October 28, 2010, pursuant to the credit facility’s accordion feature, we increased the availability under the facility to $750.0 million in the aggregate. Amounts drawn under the credit facility are available in U.S. dollars or euros and bear interest at variable rates based on either LIBOR plus a margin that varies based on our credit rating or the alternative base rate as defined in the agreement.

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; hedging arrangements outside the ordinary course of business; and sale-leaseback transactions. The facility also requires us to maintain certain financial ratios. 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, 2010, there were no borrowings or letters of credit outstanding under the facility.

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Our indebtedness consisted of the following at December 31:

	2010		2009
Senior unsecured revolving credit facility	$	—	$	—
7 3/8% Senior Notes due 2014, net of unamortized discount of $1.4 million at December 31, 2009		—		498.6
8 1/2% Senior Notes due 2019, net of unamortized discount of $1.6 million and $1.7 million, respectively		498.4		498.3
6 7/8% Senior Notes due 2020		900.0		—
7 7/8% Senior Notes due 2040		300.0		—
MARAD notes, net of unamortized fair value discount of $1.4 million and $1.9 million, respectively		165.3		195.1
Total debt		1,863.7		1,192.0
Less: current portion of long-term debt		30.3		30.3
Long-term debt	$	1,833.4	$	1,161.7

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 2019 notes bear interest at 8.5% per annum, payable semiannually. The 2019 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. The 2019 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.

6 7/8% Senior Notes due 2020 and 7 7/8% Senior Notes due 2040

On August 6, 2010, we completed an offering of $900.0 million aggregate principal amount of our 6 7/8% Senior Notes due 2020 and $300.0 million aggregate principal amount of our 7 7/8% Senior Notes due 2040. The 2020 notes and the 2040 notes bear interest at 6.875% and 7.875%, respectively, per annum, payable semiannually. The 2020 notes and 2040 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. Upon a specified change in control event that results in a ratings decline, we will be required to make an offer to repurchase the 2020 notes and the 2040 notes at a repurchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest through the applicable repurchase date. The notes of each series are subject to redemption, in whole at any time or in part from time to time, at our option, 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.

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, 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.

Redemption of 7 3/8% Senior Notes due 2014

On September 5, 2010, we redeemed all of our outstanding 7 3/8% Senior Notes due 2014 with a portion of the proceeds from the issuance of the 2020 notes and 2040 notes. The aggregate principal amount of $500.0 million was redeemed at a price of 102.458% of the principal amount, plus accrued and unpaid interest to the redemption date. As a result of the redemption of the 2014 notes, we recognized a charge of $16.4 million during the third quarter of 2010 related to the prepayment premium and write-off of unamortized debt issuance costs and discount related to the notes, which is included in “Refinancing charges” for the year ended December 31, 2010.

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Redemption of 3 1/4% Convertible Senior Notes due 2033

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 contingent interest) 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.

Future Maturities

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

	Amount
2011	$	30.3
2012		30.3
2013		30.3
2014		30.3
2015		30.3
Thereafter		1,712.2
	$	1,863.7

NOTE 5. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, foreign currency forward contracts and debt. 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. The estimated fair value of our debt at December 31, 2010 and December 31, 2009 was $2,030.2 million and $1,307.6 million, respectively, which differs from the carrying amounts of $1,863.7 million and $1,192.0 million, respectively, included in our consolidated balance sheets. The fair value of our debt has been estimated based on quarter- and year-end quoted market prices.

The following table presents our financial instruments measured at fair value on a recurring basis:

				Quoted Prices		Significant			Significant
				in		Other			Unobservable
				Active Markets		Observable Inputs			Inputs
	Total			(Level 1)		(Level 2)			(Level 3)
December 31, 2010
Derivative Financial Instruments
Foreign currency forward contracts	$	—		$	—	$	—		$	—
December 31, 2009
Derivative Financial Instruments
Foreign currency forward contracts	$	(0.1	)	$	—	$	(0.1	)	$	—

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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.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy or any changes in the valuation techniques used during 2010.

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

We have a foreign currency hedging program to mitigate 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 effect 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 $5.8 million and $6.0 million at December 31, 2010 and 2009, respectively.

All of our foreign currency forward contracts were accounted for as cash flow hedges under ASC Topic 815, Derivatives and Hedging. The fair market value of these derivative instruments is included in 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 revaluation of these liabilities from euros to U.S. dollars included in other income (expense). Amounts recorded in accumulated other comprehensive income associated with the derivative instruments are subsequently reclassed into other income (expense) 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 nominal liability at December 31, 2010 and a liability of approximately $0.1 million at December 31, 2009. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between derivative contracts and the hedged 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, 2010 and 2009 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:

	2010			2009
Net unrealized gain (loss) at beginning of period	$	(0.1	)	$	0.2
Activity during period:
Settlement of forward contracts outstanding at beginning of period		0.1			(0.2	)
Net unrealized gain on outstanding foreign currency forward contracts		—			(0.1	)
Net unrealized gain at end of period	$	—		$	(0.1	)

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NOTE 6. 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.

NOTE 7. INCOME TAXES

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

	2010			2009		2008
U.S.:
Current	$	0.6		$	0.6	$	20.4
Deferred		(35.3	)		19.0		18.9
Total U.S.		(34.7	)		19.6		39.3
Foreign:
Current		42.1			51.9		93.6
Deferred		1.2			0.3		0.6
Total foreign		43.3			52.2		94.2
Income taxes	$	8.6		$	71.8	$	133.5

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

	2010						2009						2008
	Amount			Rate (%)			Amount			Rate (%)			Amount			Rate (%)
U.S. statutory rate	$	88.2			35.0		$	144.2			35.0		$	224.8			35.0
Taxes on foreign earnings at lesser than the U.S. statutory rate		(75.6	)		(30.0	)		(85.9	)		(20.8	)		(96.1	)		(15.0	)
Finalization of prior period tax returns		(12.8	)		(5.1	)		(6.8	)		(1.6	)		(1.6	)		(0.2	)
Change in unrecognized tax benefits		3.7			1.5			1.4			0.3			4.2			0.6
Nondeductible fines and penalties		0.4			0.1			19.9			4.8			0.1			—
Other		4.7			1.9			(1.0	)		(0.3	)		2.1			0.4
Income taxes	$	8.6			3.4		$	71.8			17.4		$	133.5			20.8

The 2010 effective tax rate is below the U.S. statutory tax rate primarily due to lower income from continuing operations in 2010, tax benefits related to the adjustment of intercompany pricing in the completion of our 2009 tax return during the third quarter of 2010, and an increased proportion of income in lower tax jurisdictions. 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 domestic and foreign components of income from continuing operations before income taxes were as follows for the years ended December 31:

	2010			2009		2008
U.S.	$	(64.1	)	$	15.7	$	193.6
Foreign		316.1			396.4		448.6
Income from continuing operations before income taxes	$	252.0		$	412.1	$	642.2

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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:

	2010			2009
Deferred tax assets:
Operating loss carryforwards	$	38.0		$	27.2
Tax credit carryforwards		54.4			25.8
Employee stock-based awards and other benefits		32.0			35.3
Other		6.7			7.6
Subtotal		131.1			95.9
Valuation allowance		(31.9	)		(27.2	)
Total		99.2			68.7
Deferred tax liabilities:
Depreciation		148.1			148.4
Other		1.9			1.4
Total		150.0			149.8
Net deferred tax liability(1)	$	50.8		$	81.1

(1) The change in deferred tax liability of $30.3 million between December 31, 2010 and 2009 is different from the 2010 reported deferred tax benefit of $34.1 million primarily due to 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 $2,235.9 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, 2010, we had deferred tax assets of $38.0 million relating to $268.4 million of net operating loss (“NOL”) carryforwards, $0.3 million of non-expiring Alternative Minimum Tax (“AMT”) credits, and $54.1 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 $55.8 million of losses that do not expire and $212.6 million that could expire starting in 2011 through 2030. We have recognized a $31.9 million valuation allowance related to the foreign NOL carryforwards, primarily relating to countries where we no longer operate or do not expect to generate future taxable income, 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.

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, 2010 and 2009, we have approximately $40.8 million and $45.6 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, 2010 and 2009, we have approximately $13.4 million and $12.5 million, respectively, of accrued interest and penalties related to uncertain tax positions on the consolidated balance sheet. During 2010 and 2009, we recorded interest and penalties of $0.9 million and $1.5 million, respectively, through the consolidated statement of operations.

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

	2010			2009
Balance at the beginning of the year	$	45.6		$	45.1
Increase related to prior period tax positions		3.7			5.7
Increase related to current period tax positions		—			2.4
Settlements		—			(0.3	)
Amounts transferred to Seahawk		—			(2.4	)
Recognition of benefits from clarification in tax laws		—			(5.1	)
Foreign Currency Translations		(8.5	)		0.2
Balance at the end of the year	$	40.8		$	45.6

For jurisdictions other than the United States, tax years 1999 through 2010 remain open to examination by the major taxing jurisdictions. With regard to the United States, tax years 2007 through 2010 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.

NOTE 8. 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, 2010 and 2009, no shares of preferred stock were outstanding.

Common Stock

In connection with the retirement in the second quarter of 2008 of our 3¹/4% Convertible Senior Notes due 2033, we issued a total of 5.0 million shares of common stock to the holders (See Note 4).

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.

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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.

On February 6, 2011, we entered into a merger agreement with Ensco plc and two of its subsidiaries. Pursuant to the merger agreement and subject to the conditions provided in the agreement, we will merge with one of the subsidiaries and become an indirect, wholly owned subsidiary of Ensco. In connection with the merger agreement, we amended the plan such that none of (i) the announcement of the merger, (ii) the execution, delivery and performance of the merger agreement and the acquisition of, or right or obligation to acquire, beneficial ownership of our common stock as a result of the execution of the merger agreement, (iii) the conversion of our common stock into the right to receive the merger consideration or (iv) the consummation of the merger or any other transaction contemplated by the merger agreement will cause (x) Ensco, its subsidiaries party to the merger or any of their affiliates or associates to become an acquiring person, or (y) the occurrence of a “flip-in event”, a “flip-over event”, a “distribution date” or a “stock acquisition date” under the plan. In addition, we amended the plan to provide that the rights will expire (i) immediately prior to the effective time of the merger, if the merger is completed, or (ii) on the later of (x) the date on which the merger agreement is terminated or (y) September 30, 2011, the expiration date of the plan prior to the amendment.

NOTE 9. EARNINGS PER SHARE

The following table is a reconciliation of the numerator and the denominator of our basic and diluted earnings per share from continuing operations for the years ended December 31:

	2010			2009			2008
Income from continuing operations	$	243.4		$	340.3		$	508.7
Income from continuing operations allocated to non-vested share awards (participating securities)		(2.9	)		(5.1	)		(5.4	)
Income from continuing operations — basic		240.5			335.2			503.3
Interest expense on convertible notes		—			—			5.1
Income tax effect		—			—			(1.8	)
Income from continuing operations — diluted	$	240.5		$	335.2		$	506.6
Weighted average shares of common stock outstanding — basic		175.6			173.7			170.6
Convertible notes		—			—			4.1
Stock options		0.5			0.3			0.5
Restricted stock awards		0.1			—			—
Weighted average shares of common stock outstanding — diluted		176.2			174.0			175.2
Income from continuing operations per share:
Basic	$	1.37		$	1.93		$	2.95
Diluted	$	1.37		$	1.92		$	2.89

The calculation of weighted average shares of common stock outstanding — diluted, as adjusted, excludes 0.8 million, 2.0 million and 1.2 million of common stock issuable pursuant to outstanding stock options for the years ended December 31, 2010, 2009 and 2008, respectively, because their effect was antidilutive.

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NOTE 10. 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, performance awards and cash awards to officers and other key employees. Directors may be granted or awarded the same types of awards as employees, except that directors may not be granted or awarded cash awards. 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 in August 2009. 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.

As of December 31, 2010, one of our plans had shares available for future option grants or other awards. Under the 2007 Long-Term Incentive Plan, approximately 4.7 million shares are available for award.

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

	2010
Operating costs, excluding depreciation and amortization	$	16.1
General and administrative, excluding depreciation and amortization		16.6
Stock-based compensation expense before income taxes		32.7
Income tax benefit		(9.2	)
Total stock-based compensation expense after income taxes	$	23.5

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
	2010			2009			2008			2010
Dividend yield		0.0	%		0.0	%		0.0	%		0.0	%
Expected volatility		38.6	%		31.8	%		35.1	%		38.6	%
Risk-free interest rate		2.4	%		1.7	%		3.3	%		0.2	%
Expected life		4.2 years		5.3 years			5.3 years			0.5 years
Weighted average grant-date fair value of stock options granted	$	10.15		$	5.60		$	12.92		$	6.78

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, 2009		3,148	$	22.77
Granted		451		29.60
Exercised		297		17.54
Forfeited		—		—
Expired		3		17.61
Outstanding as of December 31, 2010		3,299	$	24.18		6.44	$	8.82
Exercisable as of December 31, 2010		1,814	$	24.69		5.15	$	8.31

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.

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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:

	2010		2009		2008
Total fair value of stock options vested (in millions)	$	6.0	$	6.5	$	5.2
Total intrinsic value of stock options exercised (in millions)	$	4.6	$	8.3	$	21.6

During 2010, 2009 and 2008, we received cash from the exercise of stock options of $5.2 million, $18.0 million and $19.0 million, respectively. Income tax benefits of $1.3 million, $2.8 million and $7.9 million were realized from the exercise of stock options for 2010, 2009 and 2008, respectively. As of December 31, 2010, there was $6.5 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 1.5 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:

	2010		2009		2008
Number of restricted stock awards (in thousands)		972		1,917		932
Fair value of restricted stock awards at date of grant (in millions)	$	27.4	$	28.4	$	31.7

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, 2009		2,459	$	16.01
Granted		972		28.28
Vested		996		25.20
Forfeited		159		23.58
Nonvested at December 31, 2010		2,276	$	23.84

As of December 31, 2010, there was $26.1 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 1.4 years.

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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.

During 2008, we recognized $0.1 million 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. Beginning in 2009, there are two purchase periods of six months each. A total of 752,485 shares remained available for issuance under the plan as of December 31, 2010. Employees purchased approximately 187,000, 202,000 and 133,000 shares in the years ended December 31, 2010, 2009 and 2008, respectively.

NOTE 11. 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 $2.2 million, $3.4 million and $3.5 million related to the SERP in 2010, 2009 and 2008, respectively. As of December 31, 2010 and 2009, the unfunded accrued pension liability was $22.6 million and $22.1 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 $2.2 million as of December 31, 2010 and approximately $1.6 million as of December 31, 2009.

One of our foreign subsidiaries has a defined benefit pension plan covering approximately 15 management employees. Benefits under this plan are typically based on years of service and final average compensation levels. The plan is managed in accordance with applicable local statutes and practices. In 2008, a review of this plan resulted in the decision to discontinue funding and close the plan to new participants. As of December 31, 2010 and 2009, the plan was overfunded $0.5 million and $0.6 million, respectively, based on the funded status of the plan.

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, $7.0 million and $9.2 million in 2010, 2009 and 2008, respectively.

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NOTE 12. COMMITMENTS AND CONTINGENCIES

Leases

At December 31, 2010, 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
2011	$	9.7
2012		7.7
2013		5.5
2014		4.4
2015		4.4
Thereafter		10.2
	$	41.9

FCPA Investigation

We have resolved with the U.S. Department of Justice and the Securities and Exchange Commission our previously disclosed investigations into potential violations of the U.S. Foreign Corrupt Practices Act. In connection with the settlements, we paid a total of $56.2 million in penalties, disgorgement and interest as described below. We had accrued this amount in the fourth quarter of 2009.

The settlement with the DOJ included a deferred prosecution agreement (“DPA”) between us and the DOJ and a guilty plea by our French subsidiary, Pride Forasol S.A.S., to FCPA-related charges. Under the DPA, the DOJ agreed to defer the prosecution of certain FCPA-related charges against us and agreed not to bring any further criminal or civil charges against us or any of our subsidiaries related to either any of the conduct set forth in the statement of facts attached to the DPA or any other information we disclosed to the DOJ prior to the execution of the DPA. We agreed, among other things, to continue to cooperate with the DOJ, to continue to review and maintain our anti-bribery compliance program and to submit to the DOJ three annual written reports regarding our progress and experience in maintaining and, as appropriate, enhancing our compliance policies and procedures. If we comply with the terms of the DPA, the deferred charges against us will be dismissed with prejudice. If, during the term of the DPA, the DOJ determines that we have committed a felony under federal law, provided deliberately false information or otherwise breached the DPA, we could be subject to prosecution and penalties for any criminal violation of which the DOJ has knowledge, including the deferred charges.

In December 2010, pursuant to a plea agreement, Pride Forasol S.A.S. pled guilty in U.S. District Court to conspiracy and FCPA charges. Pride Forasol S.A.S. was sentenced to pay a criminal fine of $32.6 million and to serve a three-year term of organizational probation.

The SEC investigation was resolved in November 2010. Without admitting or denying the allegations in a civil complaint filed by the SEC, we consented to the entry of a final judgment ordering disgorgement plus pre-judgment interest totaling $23.6 million and a permanent injunction against future violations of the FCPA.

We have received preliminary inquiries from governmental authorities of certain of the countries referenced in our settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other 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. At this early stage of such inquiries, we are unable to determine what, if any, legal liability may result. 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 and derivative cases with respect to these matters, please see the discussion below under “—Demand Letter and Derivative Cases.” In addition, disclosure of the subject matter of the investigations and settlements 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. 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.

We cannot currently predict what, if any, actions may be taken by 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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In addition, in connection with the investigation, our former Chief Operating Officer resigned as an officer effective May 31, 2006 and remained in the capacity of an employee to assist us with the investigation and to be available for consultation and to answer questions relating to our business. He had agreed to retire upon the conclusion of the investigation, and his right to receive retirement benefits was subject to the determination by our board of directors that we did not have cause (as defined in his retirement agreement with us) to terminate his employment. The board of directors determined that we did not have requisite cause to terminate his employment and that his retirement date was December 31, 2010.

Arbitration Matter

In March 2002, Pride Offshore, Inc. (now Seahawk Drilling, Inc.) entered into contracts with BP America Production Co. to design, engineer, manage construction of and commission, as well as operate the drilling package on, the Mad Dog, a platform owned by BP America in the U.S. Gulf of Mexico. In 2004, the drilling package was accepted by BP America, and Pride Offshore’s work under the operation contract commenced. In September 2008, the drilling package was destroyed and the platform was damaged in Hurricane Ike. In September 2009, BP America and an affiliate, on behalf of itself and its joint venture partners, filed an arbitration notice under the contracts, claiming that Pride Offshore breached its express and implied warranties under the construction contract and was liable for fault and gross fault in performing the contracts. Under our master separation agreement with Seahawk entered into at the time of the Seahawk spin-off in August 2009, we agreed to assume any obligations arising from the BP America contracts discussed above, which would include potential obligations arising from the construction of the drilling package. Effective January 14, 2011, we reached a settlement with BP America resolving all matters in dispute in the arbitration. Under this settlement, we funded a $250,000 payment to BP America, the amount of our deductible under the applicable insurance policies, and our insurance underwriters funded the balance of the settlement payment. We believe that the matter has not adversely affected, and is not likely to adversely affect, our relationship with BP America in any material respect.

Environmental Matters

We are currently subject to pending notices of assessment issued from 2002 to 2010 pursuant to which governmental authorities in Brazil are seeking fines in an aggregate amount of approximately $1.4 million, based on exchange rates as of December 31, 2010, 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. As of December 31, 2010, we have an accrual of $1.4 million for potential liability related to these matters.

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. In addition, a criminal investigation of the incident was initiated by a prosecutor in Tarragona, Spain in July 2010, and the administrative proceedings have been suspended pending the outcome of this investigation. We do not know at this time what, if any, involvement we may have in this investigation. We intend to defend ourselves vigorously in the administrative proceeding and any criminal investigation of us and, based on the information available to us at this time, we do not expect the outcome of the proceedings 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 proceedings.

Demand Letter and Derivative Cases

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 September 2009, in response to this letter, the board of directors formed a special committee, which retained independent counsel to advise it. The committee commenced an evaluation of the issues raised by the letter in an effort to determine a course of action for the company.

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Subsequent to the receipt of the 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 in an unspecified amount 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, but the demand letter referenced above remains in effect.

On April 14, 2010, Edward Ferguson, a purported stockholder of Pride, filed a derivative action in the state court of Harris County, Texas against all of our current directors and us, as nominal defendant. The lawsuit alleges that the individual defendants breached their fiduciary duties to us related to the issues described above under “—FCPA Investigation.” Among other remedies, the lawsuit seeks damages in an unspecified amount and equitable relief against the individual defendants, along with an award of attorney fees and other costs and expenses to the plaintiff. On April 15, 2010, Lawrence Dixon, another purported stockholder, filed a substantially similar lawsuit in the state court of Harris County, Texas against the same defendants. These two lawsuits have been consolidated. The parties agreed to a deferral of the matter to await further developments in the FCPA investigation. After the conclusion of that investigation (see “—FCPA Investigation”), the plaintiffs filed a consolidated amended petition on January 18, 2011, raising allegations substantially similar to those made in the prior lawsuits.

On February 9, 2011, the plaintiffs filed a further amendment to their petition adding claims related to our proposed merger with Ensco plc. Please read Note 17 for additional information about the transaction. In this latest amendment, the plaintiffs contend that the proposed merger was motivated by a desire to extinguish the alleged liability related to the derivative action. The plaintiffs also contend that the proposed merger does not provide fair value to our stockholders, and that various provisions of the merger agreement are improperly designed to prevent any competing bids. The plaintiffs assert claims for breach of fiduciary duty, aiding and abetting such breaches, abuse of control, and mismanagement. They contend that their breach of fiduciary duty claim with respect to the proposed merger should be certified as a class action, that the merger agreement should be declared unenforceable, and that the proposed merger should be enjoined. The plaintiffs seek unspecified damages and other relief as well.

In December 2010, the special committee completed its evaluation of the issues surrounding the FCPA investigation. The committee analyzed the issues raised by the demand letter and the then pending lawsuits and conducted its own investigation into the matter. The committee concluded that it was not in the interest of our company or our stockholders to pursue litigation related to the matter. These conclusions were summarized for the board of directors in December 2010. On January 28, 2011, the special committee met and evaluated whether the allegations raised in the amended petition in the Ferguson matter filed on January 18, 2011 raised any issues that would alter its conclusion. The committee determined that the new filing did not alter its conclusion that litigation of these matters was not in the interest of our company or our stockholders and that such litigation should not be pursued. On February 14, 2011, we received the report of the special committee dated December 8, 2010, as well as committee minutes reflecting the conclusions reached in the meeting of January 28, 2011.

On February 9, 2011, Cary Abrams, a purported stockholder of Pride, filed a class action petition in state court in Harris County, Texas requesting temporary and permanent injunctive relief enjoining the proposed merger with Ensco and rescission of the merger if consummated. On February 10, 2011, Astor BK Realty Trust, another purported stockholder of Pride, filed a substantially similar lawsuit in Harris County, Texas. The lawsuits allege that all of our current directors breached their fiduciary duties by agreeing to inadequate consideration for our stockholders and by approving a merger agreement that includes deal protection devices allegedly designed to ensure that we will not receive a superior offer. The lawsuits also allege that we and Ensco aided and abetted the directors in the breaches of their fiduciary duties. The plaintiffs seek unspecified damages and other relief as well.

On February 10, 2011, Saratoga Advantage Trust, a purported stockholder of Pride, filed a class action complaint in the Delaware Chancery Court seeking preliminary and permanent injunctive relief enjoining the proposed merger with Ensco. On February 17, 2011, Elizabeth Wiggs - Jacques, another purported stockholder of Pride, filed a substantially similar lawsuit in the Delaware Chancery Court. The plaintiffs allege that all of our current directors breached their fiduciary duties by approving the merger agreement because it provides inadequate consideration to our stockholders and contains provisions designed to ensure that we will not receive a competing superior proposal. The plaintiffs also allege that we and Ensco aided and abetted the directors in purportedly breaching their fiduciary duties. In addition, the plaintiffs seek rescission of the merger should it be consummated, as well as other unspecified equitable relief.

We anticipate the filing of other similar lawsuits in the coming days.

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 have been and are expected to continue to be covered by our insurance. Under the master separation agreement between us and Seahawk, Seahawk agreed to be responsible for any removal costs, legal settlements and legal costs associated with the Pride Wyoming not covered by insurance. The master separation agreement also provided that, at Seahawk’s request, we would finance, on a revolving basis, some or all of the costs for removal of the wreckage and salvage operations until receipt of insurance proceeds. During 2010, Seahawk requested that we pay various invoices related to the removal of the wreckage. We paid the invoices and were reimbursed for the entire amount under our insurance policies. The removal of the wreckage was completed in December 2010 and the remaining removal costs are covered by our insurance policies and will be paid by the insurance underwriters.

Seahawk Tax-Related Credit Support

In 2006, 2007 and 2009, Seahawk received tax assessments from the Mexican government related to the operations of certain of Seahawk’s subsidiaries. Pursuant to local statutory requirements, Seahawk has provided and may provide additional surety bonds, letters of credit, or other suitable collateral to contest these assessments. Pursuant to a tax support agreement between us and Seahawk, we agreed, at Seahawk’s request, to guarantee or indemnify the issuer of any such surety bonds, letters of credit, 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 the assessments could total up to approximately $161.6 million, based on exchange rates as of December 31, 2010. On September 15, 2010, Seahawk requested that we provide credit support for four letters of credit issued for the appeals of four of Seahawk’s tax assessments. The amount of the request totaled approximately $48.4 million, based on exchange rates as of December 31, 2010. On October 28, 2010, we provided credit support in satisfaction of this request. As of December 31, 2010, we have an accrual of $2.4 million related to this matter, which represents the fair value of our guarantee. Pursuant to the tax support agreement, Seahawk is required to pay us a fee based on the actual credit support provided. Seahawk’s quarterly fee payment due on December 31, 2010 was not made, which had the effect of terminating Pride’s obligation to provide further credit support under the tax support agreement. Further, on February 9, 2011, we sent a demand letter to Seahawk which notified them of their breach of this agreement, and we requested cash-collateralization from them for the credit support that we previously provided on their behalf, as permitted under the terms of the agreement. In connection with its bankruptcy filing, Seahawk is seeking to terminate its reimbursement obligations under the tax support agreement.

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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 $544.8 million at December 31, 2010. These letters of credit and surety bonds are issued under a number of facilities provided by several banks and other financial institutions.

NOTE 13. RESTRUCTURING COSTS

During the fourth quarter of 2010, we initiated a plan to open a regional headquarter for the Eastern hemisphere in the Netherlands and a project to consolidate our offices in France, in order to reduce costs and improve operating efficiencies. The restructuring effort contemplates closing down one office and reducing the overall workforce in France. We expect the restructuring to be completed in the third quarter of 2011 and the associated costs to be paid using cash from operations. The costs to be incurred for the restructuring will be primarily related to payments to be made under ongoing and one-time termination benefit arrangements; however, the details of our proposed plan are subject to negotiations with, and the formal opinion of, a local labor committee.

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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 drillships and semisubmersible 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 Jackup, which consists of our jackup 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.

	2010			2009			2008
Deepwater revenues:
Revenues, excluding reimbursables	$	916.3		$	810.3		$	874.6
Reimbursable revenues		14.2			12.8			7.6
Total Deepwater revenues		930.5			823.1			882.2
Midwater revenues:
Revenues, excluding reimbursables		365.8			412.9			419.5
Reimbursable revenues		1.7			6.5			6.0
Total Midwater revenues		367.5			419.4			425.5
Independent Leg Jackup revenues:
Revenues, excluding reimbursables		89.4			264.0			273.9
Reimbursable revenues		1.3			1.3			1.3
Total Independent Leg Jackup revenues		90.7			265.3			275.2
Other		70.9			83.0			119.2
Corporate		0.5			3.4			0.5
Total revenues	$	1,460.1		$	1,594.2		$	1,702.6
Earnings (loss) from continuing operations:
Deepwater	$	344.8		$	348.3		$	454.7
Midwater		66.5			129.0			163.6
Independent Leg Jackups		(25.1	)		105.4			133.2
Other		3.8			4.8			7.8
Corporate		(114.8	)		(174.2	)		(132.2	)
Total	$	275.2		$	413.3		$	627.1
Capital expenditures:
Deepwater	$	1,087.2		$	893.6			714.4
Midwater		80.5			39.6			169.3
Independent Leg Jackups		31.3			11.6			40.1
Other		4.3			2.8			7.5
Corporate		50.0			21.8			29.4
Discontinued operations		—			25.0			23.3
Total	$	1,253.3		$	994.4		$	984.0
Depreciation and amortization:
Deepwater	$	96.9		$	76.7		$	72.2
Midwater		49.2			45.3			42.0
Independent Leg Jackups		30.6			29.0			26.8
Other		0.3			0.3			1.7
Corporate		7.0			7.7			4.6
Total	$	184.0		$	159.0		$	147.3

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We measure segment assets as property and equipment. Our total long-lived assets, net, by segment as of December 31, 2010 and 2009 were as follows:

	2010		2009
Total long-lived assets:
Deepwater	$	4,826.7	$	3,836.1
Midwater		716.3		680.5
Independent Leg Jackups		266.5		261.2
Other		19.0		23.1
Corporate		132.7		89.4
Total	$	5,961.2	$	4,890.3

Our significant customers for the years ended December 31, 2010, 2009 and 2008, were as follows:

	2010			2009			2008
Petroleos Brasileiro S.A.		38	%		33	%		25	%
Total S.A.		18	%		16	%		13	%
BP America and affiliates		15	%		4	%		13	%
Exxon Mobil Corporation		3	%		7	%		11	%

For the years ended December 31, 2010, 2009 and 2008, we derived 94%, 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 were performed are as follows for years ended December 31:

	2010		2009		2008
Brazil	$	740.2	$	586.0	$	513.7
Angola		322.3		489.6		532.1
Other countries		316.2		469.3		592.0
All International		1,378.7		1,544.9		1,637.8
United States		81.4		49.3		64.8
Total	$	1,460.1	$	1,594.2	$	1,702.6

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, by geographic area, including our drillships under construction in South Korea, are as follows at December 31:

	2010		2009
Brazil	$	1,819.0	$	1,649.8
South Korea		967.3		1,682.3
Angola		556.2		724.1
Mexico		—		0.8
Other countries		691.8		660.7
All International		4,034.3		4,717.7
United States		1,926.9		172.6
Total	$	5,961.2	$	4,890.3

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NOTE 15. OTHER SUPPLEMENTAL INFORMATION

Other current assets consisted of the following at December 31:

	2010		2009
Other receivables	$	41.7	$	112.3
Prepaid expenses		34.6		23.5
Deferred mobilization and inspection costs		33.5		23.3
Insurance receivables		7.5		1.8
Other		10.0		6.7
Total	$	127.3	$	167.6

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

	2010			2009
Payroll and benefits	$	68.3		$	59.7
Interest		39.6			21.9
Deferred mobilization revenues		25.5			65.5
Current income taxes		8.9			13.9
Taxes other than income		6.8			5.4
Department of Justice and Securities and Exchange Commission fines		—			56.2
Importation duties		—			13.6
Short-term indemnity		(0.1	)		35.2
Other		68.0			68.3
Total	$	217.0		$	339.7

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

	2010		2009			2008
Rental expense	$	41.1	$	48.7		$	46.8
Other income (loss), net
Foreign exchange gain (loss)	$	3.9	$	(5.5	)	$	10.2
Realized and unrealized changes in fair value of derivatives		—		—			—
Equity earnings in unconsolidated subsidiaries		—		—			0.2
Other		0.1		1.4			10.2
Total	$	4.0	$	(4.1	)	$	20.6

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

	2010			2009			2008
Decrease (increase) in:
Trade receivables	$	11.6		$	142.4		$	(80.8	)
Other current assets		50.4			(16.4	)		(11.0	)
Other assets		13.2			(18.3	)		(2.5	)
Increase (decrease) in:
Accounts payable		(29.6	)		(14.9	)		58.8
Accrued expenses		(81.7	)		44.1			(15.9	)
Other liabilities		(3.3	)		5.9			24.5
Net effect of changes in operating accounts	$	(39.4	)	$	142.8		$	(26.9	)
Cash paid during the year for:
Interest	$	94.4		$	70.2		$	56.1
Income taxes — U.S., net		0.6			0.6			2.4
Income taxes — foreign, net		41.9			123.7			145.8
Change in capital expenditures in accounts payable		10.6			24.0			(54.6	)

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NOTE 16. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter
2010
Revenues	$	362.8		$	350.3		$	346.2		$	400.8
Earnings from operations		86.3			57.3			56.0			75.6
Income from continuing operations, net of tax		80.7			57.7			42.8			62.2
Loss from discontinued operations, net of tax		(7.7	)		(0.2	)		(6.3	)		(10.1	)
Net income		73.0			57.5			36.5			52.1
Basic earnings per share:
Income from continuing operations	$	0.45		$	0.32		$	0.24		$	0.35
Loss from discontinued operations		(0.04	)		—			(0.04	)		(0.06	)
Net income	$	0.41		$	0.32		$	0.20		$	0.29
Diluted earnings per share:
Income from continuing operations		0.45			0.32			0.24			0.35
Loss from discontinued operations		(0.04	)		—			(0.04	)		(0.06	)
Net income	$	0.41		$	0.32		$	0.20		$	0.29
2009
Revenues	$	451.9		$	439.5		$	386.1		$	316.7
Earnings from operations		172.4			164.3			100.1			(23.5	)
Income (loss) from continuing operations, net of tax		148.9			134.7			79.9			(23.2	)
Income (loss) from discontinued operations, net of tax		10.0			(10.6	)		(44.3	)		(9.6	)
Net income (loss)		158.9			124.1			35.6			(32.8	)
Basic earnings per share:
Income (loss) from continuing operations	$	0.84		$	0.76		$	0.45		$	(0.13	)
Income (loss) from discontinued operations		0.06			(0.06	)		(0.25	)		(0.06	)
Net income (loss)	$	0.90		$	0.70		$	0.20		$	(0.19	)
Diluted earnings per share:
Income (loss) from continuing operations		0.84			0.76			0.45			(0.13	)
Income (loss) from discontinued operations		0.06			(0.06	)		(0.25	)		(0.06	)
Net income (loss)	$	0.90		$	0.70		$	0.20		$	(0.19	)

NOTE 17. SUBSEQUENT EVENTS

Merger with Ensco

On February 6, 2011, we entered into a merger agreement with Ensco plc and two of its subsidiaries. Pursuant to the merger agreement and subject to the conditions provided in the agreement, we will merge with one of the subsidiaries and become an indirect, wholly owned subsidiary of Ensco.

As a result of the merger, each outstanding share of our common stock (other than shares of our common stock held by us, Ensco or any of our respective wholly owned subsidiaries (which will be cancelled as a result of the merger), those shares with respect to which appraisal rights under Delaware law are properly exercised and not withdrawn and other shares held by certain U.K. residents if determined by Ensco) will be converted into the right to receive $15.60 in cash and 0.4778 American depositary shares, representing Class A ordinary shares of Ensco (each, an “Ensco ADS”). Under certain circumstances, UK residents may receive all cash consideration as a result of compliance with legal requirements.

At the effective time of the merger, all of our outstanding equity awards will vest. Shares of our common stock will be paid to holders of restricted stock units and such stock will be converted into the right to receive the merger consideration. In addition, all vested and unexercised stock options will be assumed by Ensco and converted into equivalent options to acquire Ensco ADSs based on an exchange ratio equal to 0.4778 plus a fraction obtained by dividing $15.60 by the average closing price of Ensco ADSs for the five trading days ending three trading days before the closing of the merger.

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The completion of the merger is subject to certain conditions, including, among others, (i) the adoption of the merger agreement by our stockholders and the approval of the delivery of the Ensco ADSs by the shareholders of Ensco, (ii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the absence of any pending governmental proceeding or order to restrain the transactions in specified jurisdictions, including the United States, (iii) subject to certain materiality exceptions, the accuracy of the representations and warranties made by the parties and compliance by the parties with their respective covenants and agreements under the merger agreement, (iv) the declaration of the effectiveness by the Securities and Exchange Commission of the registration statements on Form S-4 and Form F-6 and, if applicable, the UK Listing Authority shall have approved Ensco’s prospectus, (v) the Ensco ADSs to be delivered pursuant to the merger shall have been authorized for listing on the New York Stock Exchange and (vi) other customary closing conditions.

Each party to the merger agreements has made representations and warranties in the merger agreement. We and Ensco have made covenants to conduct our respective businesses in the ordinary course between the execution of the merger agreement and the consummation of the merger and covenants not to engage in certain kinds of transactions during that period. We and Ensco have made certain additional covenants, including, among others, covenants, subject to certain exceptions, (i) not to solicit proposals regarding alternative business combination transactions, (ii) not to enter into discussions concerning, or provide confidential information in connection with, alternative business combination transactions, (iii) to cause stockholder meetings and shareholder meetings to be held to approve the delivery of Ensco ADSs in connection with the merger and the adoption of the merger agreement, respectively, and (iv) for our respective boards of directors to recommend approval of such proposals. In addition, Ensco has made covenants to use its reasonable best efforts to obtain financing on the same or more favorable terms as in the commitment letter described below.

The merger agreement may be terminated under certain circumstances, including if either Ensco’s or our board of directors has determined in good faith that it has received a superior proposal and otherwise complies with certain terms of the merger agreement. Upon the termination of the merger agreement, under specified circumstances, including the failure to obtain a party’s stockholder approval, such party will be required to pay a fee to the other party of $50 million. Upon the termination of the merger agreement under other specified circumstances, including (i) the decision to accept a superior proposal, (ii) a change in board of director recommendation or (iii) a failure to obtain stockholder approval after public disclosure of an alternative business combination proposal before the stockholder meeting and either the board of directors determines such proposal to be a superior proposal or, within 12 months after termination of the merger agreement, the party enters into a definitive agreement or consummates an alternative business combination proposal, such party will be required to pay the other party a termination fee of $260 million.

Additionally, Ensco has agreed that it will cause two of our current, non-employee directors designated by us to be appointed to the board of directors of Ensco at the closing of the merger. Each designee will be appointed to the class of directors selected by Ensco and will stand for election for the remaining portion of the term of office, if any, for such class at the next annual general meeting of Ensco shareholders for which a notice of the meeting has not been sent at the time of the appointment. Ensco management will recommend to the nominating, governance and compensation committee of the Ensco board of directors that such designees be nominated for election at such annual general meeting.

Ensco has advised us that, in connection with the merger agreement, Ensco entered into a bridge commitment letter pursuant to which certain lenders committed to provide $2.75 billion under an unsecured bridge term facility to fund a portion of the financing for the transactions contemplated by the merger agreement. The commitment is subject to various conditions, including the absence of a material adverse effect on us or Ensco having occurred, the receipt by Ensco of investment grade credit ratings, the execution of satisfactory documentation and other customary closing conditions. The closing of the financing is not a condition to the completion of the merger.

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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 (the “Exchange Act”) 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, 2010 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, 2010, management has conducted an assessment, using the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Because of its inherent limitations, 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, 2010.

KPMG LLP, our independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2010 as stated in their report, which appears in “Item 8. Financial Statements and Supplementary Data” of this annual report.

(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 2010 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, other than as set forth below, 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, 2010.

Executive Officers of Registrant

We have presented below information about our executive officers as of February 18, 2011. 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		58	President, Chief Executive Officer
Brian C. Voegele		50	Senior Vice President and Chief Financial Officer
Lonnie D. Bane		52	Senior Vice President, Human Resources and Administration
W. Gregory Looser		41	Senior Vice President and Chief Administrative Officer
Kevin C. Robert		52	Senior Vice President, Marketing and Business Development
Imran (Ron) Toufeeq		54	Senior Vice President, Operations, Asset Management and Engineering
Brady K. Long		38	Vice President, General Counsel and Secretary

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 & Giuliani 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.

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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.

Brady K. Long was appointed Vice President, General Counsel and Secretary in August 2009 and was previously Vice President, Chief Compliance Officer and Deputy General Counsel. He joined Pride in June 2005 after practicing corporate and securities law for BJ Services Company and Bracewell & Giuliani LLP.

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, 2010.

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, 2010.

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, 2010.

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, 2010.

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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	Agreement and Plan of Merger, dated as of February 6, 2011, by and among Pride, Ensco plc, ENSCO International Incorporated, and ENSCO Ventures LLC (incorporated by reference to Exhibit 2.1 to Pride’s Current Report on Form 8-K filed with the SEC on February 7, 2011, File No. 1-13289).
	2.2	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	Amendment No. 1 to Rights Agreement dated as of January 29, 2008 between Pride and American Stock Transfer & Trust Company, LLC, 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	Amendment No. 2 to Rights Agreement, dated as of February 6, 2011, between Pride and American Stock Transfer & Trust Company, LLC, as Rights Agent (incorporated by reference to Exhibit 4.1 to Pride’s Current Report on Form 8-K filed with the SEC on February 7, 2011, File No. 1-13289).
	4.5	Certificate of Designations of Series A Junior Participating Preferred Stock of Pride (incorporated by reference to Exhibit 4.3 to the Form 8-K).
	4.6	Amended and Restated Revolving Credit Agreement dated as of July 30, 2010 among Pride, the lenders from time to time parties thereto, Citibank, N.A., as administrative agent for the lenders, Natixis and Wells Fargo Bank, National Association, as syndications agent for the lenders, Bank of America, N.A., as documentation agent for the lenders, and Citibank, N.A., Natixis and Wells Fargo Bank, National Association, as issuing banks of the letters of credit thereunder (incorporated by reference to Exhibit 4.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).

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Exhibit
No.			Description
	4.7		Joinder Agreement dated as of October 28, 2010 among Pride, Citibank, N.A., as administrative agent, and NIBC Bank N.V. (incorporated by reference to Exhibit 4.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).
	4.8		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).
	4.9		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).
	4.10		Third Supplemental Indenture dated as of August 6, 2010 by and between Pride and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A.), as Trustee (incorporated by reference to Exhibit 4.3 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, 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).

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Exhibit
No.			Description
	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 (incorporated by reference to Exhibit 10.25 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.26	†	Second Amendment to ESPP (incorporated by reference to Exhibit 4.10 to Pride’s registration statement on Form S-8, Registration No. 333-168503).
	10.27	†	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).
	10.28	†	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).
	10.29	†	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).
	10.30	†	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).

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Exhibit
No.			Description
	10.31	†	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).
	10.32	†	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).
	10.33	†	Pride International, Inc. 2007 Long-Term Incentive Plan (as amended and restated) (incorporated by reference to Appendix A to Pride’s Proxy Statement on Schedule 14A for the 2010 Annual Meeting of Stockholders, File No. 1-13289).
	10.34	†	First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (as amended and restated) (incorporated by reference to Exhibit 10.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).
	10.35	†	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).
	10.36	†	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).
	10.37	†	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).
	10.38	†	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).
	10.39	†	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).
	10.40	†	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).
	10.41	†	Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement with three-year cliff vesting (incorporated by reference to Exhibit 10.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.42	†	Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement with three-year cliff vesting (with additional provisions) (incorporated by reference to Exhibit 10.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.43	†	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).
	10.44	†	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).
	10.45	†	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).
	10.46	†	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).
	10.47	†	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).

95

Exhibit
No.			Description
	10.48	†	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).
	10.49	†*	Amended and Restated Separation/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Brady K. Long.
	10.50	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and Imran Toufeeq (incorporated by reference to Exhibit 10.4 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.51	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.5 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.52	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.6 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.53	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and Lonnie B. Bane (incorporated by reference to Exhibit 10.7 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.54	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and Kevin C. Robert (incorporated by reference to Exhibit 10.8 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.55	†*	Summary of certain executive officer and director compensation arrangements.
	10.56		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

96

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 18, 2011.

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 18, 2011.

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

97

INDEX TO EXHIBITS

Exhibit
No.		Description
	2.1	Agreement and Plan of Merger, dated as of February 6, 2011, by and among Pride, Ensco plc, ENSCO International Incorporated, and ENSCO Ventures LLC (incorporated by reference to Exhibit 2.1 to Pride’s Current Report on Form 8-K filed with the SEC on February 7, 2011, File No. 1-13289).
	2.2	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	Amendment No. 1 to Rights Agreement dated as of January 29, 2008 between Pride and American Stock Transfer & Trust Company, LLC, 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	Amendment No. 2 to Rights Agreement, dated as of February 6, 2011, between Pride and American Stock Transfer & Trust Company, LLC, as Rights Agent (incorporated by reference to Exhibit 4.1 to Pride’s Current Report on Form 8-K filed with the SEC on February 7, 2011, File No. 1-13289).
	4.5	Certificate of Designations of Series A Junior Participating Preferred Stock of Pride (incorporated by reference to Exhibit 4.3 to the Form 8-K).
	4.6	Amended and Restated Revolving Credit Agreement dated as of July 30, 2010 among Pride, the lenders from time to time parties thereto, Citibank, N.A., as administrative agent for the lenders, Natixis and Wells Fargo Bank, National Association, as syndications agent for the lenders, Bank of America, N.A., as documentation agent for the lenders, and Citibank, N.A., Natixis and Wells Fargo Bank, National Association, as issuing banks of the letters of credit thereunder (incorporated by reference to Exhibit 4.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).
	4.7	Joinder Agreement dated as of October 28, 2010 among Pride, Citibank, N.A., as administrative agent, and NIBC Bank N.V. (incorporated by reference to Exhibit 4.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).
	4.8	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).
	4.9	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).
	4.10	Third Supplemental Indenture dated as of August 6, 2010 by and between Pride and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A.), as Trustee (incorporated by reference to Exhibit 4.3 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, 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.

98

Exhibit
No.		Description
	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).

99

Exhibit
No.		Description
	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 (incorporated by reference to Exhibit 10.25 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.26†	Second Amendment to ESPP (incorporated by reference to Exhibit 4.10 to Pride’s registration statement on Form S-8, Registration No. 333-168503).
	10.27†	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).
	10.28†	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).
	10.29†	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).
	10.30†	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).
	10.31†	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).
	10.32†	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).
	10.33†	Pride International, Inc. 2007 Long-Term Incentive Plan (as amended and restated) (incorporated by reference to Appendix A to Pride’s Proxy Statement on Schedule 14A for the 2010 Annual Meeting of Stockholders, File No. 1-13289).
	10.34†	First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (as amended and restated) (incorporated by reference to Exhibit 10.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).
	10.35†	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).
	10.36†	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).

100

Exhibit
No.			Description
	10.37	†	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).
	10.38	†	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).
	10.39	†	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).
	10.40	†	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).
	10.41	†	Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement with three-year cliff vesting (incorporated by reference to Exhibit 10.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.42	†	Form of 2007 Long-Term Incentive Plan Restricted Stock Unit Agreement with three-year cliff vesting (with additional provisions) (incorporated by reference to Exhibit 10.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.43	†	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).
	10.44	†	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).
	10.45	†	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).
	10.46	†	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).
	10.47	†	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).
	10.48	†	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).
	10.49	†*	Amended and Restated Separation/Non-Competition/Confidentiality Agreement dated December 31, 2008 between Pride and Brady K. Long.
	10.50	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and Imran Toufeeq (incorporated by reference to Exhibit 10.4 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.51	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and Brian C. Voegele (incorporated by reference to Exhibit 10.5 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.52	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and W. Gregory Looser (incorporated by reference to Exhibit 10.6 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.53	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and Lonnie B. Bane (incorporated by reference to Exhibit 10.7 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).

101

Exhibit
No.			Description
	10.54	†	Acknowledgment and Amendment of Employment Agreement effective January 1, 2010 between Pride and Kevin C. Robert (incorporated by reference to Exhibit 10.8 to Pride’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 1-13289).
	10.55	†*	Summary of certain executive officer and director compensation arrangements.
	10.56		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.

102