UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-13289

Pride International, Inc.

(Exact name of registrant as specified in its charter)

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

(713) 789-1400
(Registrant’s telephone number, including area code)

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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practical date.

		Outstanding as of
		May 2, 2011
Common Stock, par value $.01 per share		177,961,390

 

 

Table of Contents

		Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements			3
Consolidated Balance Sheets — March 31, 2011 and December 31, 2010			3
Consolidated Statements of Operations — Three months ended March 31, 2011 and 2010			4
Consolidated Statements of Cash Flows — Three months ended March 31, 2011 and 2010			5
Notes to Unaudited Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
Item 3. Quantitative and Qualitative Disclosures About Market Risk			39
Item 4. Controls and Procedures			39
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			40
Item 1A. Risk Factors			40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 6. Exhibits			41
Signatures			42
Exhibit 12
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

PART I — FINANCIAL INFORMATION

Item 1.		Financial Statements

Pride International, Inc.

		March 31,				December 31,
		2011				2010
		(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	45.8			$	485.0
Trade receivables, net			291.8				200.3
Deferred income taxes			15.5				10.1
Other current assets			111.1				127.3
Total current assets			464.2				822.7
PROPERTY AND EQUIPMENT			7,796.4				7,337.0
Less: accumulated depreciation			1,423.3				1,375.8
Property and equipment, net			6,373.1				5,961.2
OTHER ASSETS, NET			88.2				87.8
Total assets		$	6,925.5			$	6,871.7
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt		$	30.3			$	30.3
Accounts payable			111.1				112.3
Accrued expenses and other current liabilities			211.8				217.0
Total current liabilities			353.2				359.6
OTHER LONG-TERM LIABILITIES			101.3				101.5
LONG-TERM DEBT, NET OF CURRENT PORTION			1,826.4				1,833.4
DEFERRED INCOME TAXES			65.6				60.9
STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value; 50.0 shares authorized; none issued			—				—
Common stock, $0.01 par value; 400.0 shares authorized; 179.2 and 176.9 shares issued; 178.0 and 175.8 shares outstanding			1.8				1.8
Paid-in capital			2,140.1				2,103.0
Treasury stock, at cost; 1.2 and 1.1 shares			(27.2	)			(21.8	)
Retained earnings			2,460.0				2,429.9
Accumulated other comprehensive income			4.3				3.4
Total stockholders’ equity			4,579.0				4,516.3
Total liabilities and stockholders’ equity		$	6,925.5			$	6,871.7

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

Pride International, Inc.

		Three Months Ended
		March 31,
		2011				2010
REVENUES
Revenues, excluding reimbursable revenues		$	386.1			$	357.4
Reimbursable revenues			7.4				5.4
			393.5				362.8
COSTS AND EXPENSES
Operating costs, excluding depreciation			256.7				200.9
Reimbursable costs			6.5				4.2
Depreciation			53.0				42.1
General and administrative, excluding depreciation			35.5				29.5
Gain on sales of assets, net			—				(0.2	)
			351.7				276.5
EARNINGS FROM OPERATIONS			41.8				86.3
OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized			(4.7	)			—
Interest income			0.6				0.2
Other income (expense), net			(3.8	)			8.9
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES			33.9				95.4
INCOME TAXES			(3.0	)			(14.7	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX			30.9				80.7
LOSS FROM DISCONTINUED OPERATIONS, NET OF TAX			(0.8	)			(7.7	)
NET INCOME		$	30.1			$	73.0
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders		$	0.17			$	0.45
Loss from discontinued operations			—				(0.04	)
Net income		$	0.17			$	0.41
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders		$	0.17			$	0.45
Loss from discontinued operations			—				(0.04	)
Net income		$	0.17			$	0.41
SHARES USED IN PER SHARE CALCULATIONS
Basic			177.1				175.4
Diluted			178.2				175.9

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

Pride International, Inc.

		Three Months Ended
		March 31,
		2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	30.1			$	73.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation			53.0				42.1
Amortization and write-offs of deferred financing costs			1.0				0.6
Amortization of deferred contract liabilities			(1.5	)			(13.4	)
Gain on sales of assets, net			—				(0.2	)
Deferred income taxes			(0.8	)			2.2
Excess tax benefits from stock-based compensation			—				(2.6	)
Stock-based compensation			9.6				8.1
Other, net			0.1				0.2
Net effect of changes in operating accounts (See Note 12)			(88.5	)			(11.3	)
Increase (decrease) in deferred revenue			7.5				(0.9	)
Increase in deferred expense			5.6				2.4
NET CASH FLOWS FROM OPERATING ACTIVITIES			16.1				100.2
CASH FLOWS USED IN INVESTING ACTIVITIES:
Purchases of property and equipment			(474.1	)			(516.7	)
Proceeds from dispositions of property and equipment			—				0.4
NET CASH FLOWS USED IN INVESTING ACTIVITIES			(474.1	)			(516.3	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of borrowings			(7.1	)			(7.1	)
Net proceeds from employee stock transactions			25.9				4.3
Excess tax benefits from stock-based compensation			—				2.6
NET CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES			18.8				(0.2	)
Decrease in cash and cash equivalents			(439.2	)			(416.3	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			485.0				763.1
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	45.8			$	346.8

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

Pride International, Inc.

Notes to Unaudited Consolidated Financial Statements

NOTE 1. GENERAL

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

Our unaudited consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. We believe that the presentation and disclosures herein are adequate to make the information not misleading. In the opinion of management, the unaudited consolidated financial information included herein reflects all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of our financial position, results of operations and cash flows for the interim periods presented. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2010. The results of operations for the interim periods presented herein are not necessarily indicative of the results to be expected for a full year or any other interim period.

In the notes to the unaudited consolidated financial statements, all dollar and share amounts, other than per share amounts, in tabulations are in millions of dollars and shares, respectively, unless otherwise noted.

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 — Financial Instruments.

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.

Comprehensive Income

A reconciliation of net income to comprehensive income is as follows:

		Three Months Ended
		March 31,
		2011				2010
Net Income		$	30.1			$	73.0
Other comprehensive gains (losses), net of tax
Foreign currency translation			0.7				0.4
Foreign currency hedges			0.2				(0.1	)
Defined benefit plan			—				(1.3	)
Comprehensive Income		$	31.0			$	72.0

Reclassifications

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

NOTE 2. DISCONTINUED OPERATIONS AND OTHER DIVESTITURES

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 Drilling, Inc. (“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:

		Three Months Ended
		March 31,
		2011				2010
Revenues		$	—			$	—
Loss before taxes			(0.4	)			(0.6	)
Income taxes			(0.4	)			0.2
Loss from discontinued operations		$	(0.8	)		$	(0.4	)

In connection with the spin-off, we made a cash contribution to Seahawk of approximately $47.3 million to achieve a targeted working capital for Seahawk as of May 31, 2009 of $85 million. We and Seahawk also agreed to indemnify each other for certain liabilities that may arise or be incurred in the future attributable to our respective businesses. As of March 31, 2011, we had receivables from Seahawk of $23.6 million and an allowance of $7.3 million, which were included in other current assets, primarily related 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 Hercules Offshore, Inc. and its affiliate SD Drilling LLC, which agreed to pay base aggregate consideration consisting of approximately $25 million in cash and 22,321,425 shares of Hercules common stock. On April 5, 2011, Seahawk’s bankruptcy court approved the sale to Hercules, and on April 27, 2011 the asset sale was consummated. 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.

Sale of Latin America Land and E&P Services Segments

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 March 31, 2011, 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.

NOTE 3. PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

		March 31,				December 31,
		2011				2010
Rigs and rig equipment		$	6,175.1			$	5,256.1
Construction-in-progress — newbuild drillships			1,332.4				1,788.8
Construction-in-progress — other			200.8				204.8
Other			88.1				87.3
Property and equipment, cost			7,796.4				7,337.0
Accumulated depreciation			(1,423.3	)			(1,375.8	)
Property and equipment, net		$	6,373.1			$	5,961.2

NOTE 4. DEBT

Debt consisted of the following:

		March 31,				December 31,
		2011				2010
Senior unsecured revolving credit facility		$	—			$	—
8 1/2% Senior Notes due 2019, net of unamortized discount of $1.6 million and $1.6 million, respectively			498.4				498.4
6 7/8% Senior Notes due 2020			900.0				900.0
7 7/8% Senior Notes due 2040			300.0				300.0
MARAD notes, net of unamortized fair value discount of $1.3 million and $1.4 million, respectively			158.3				165.3
Total debt			1,856.7				1,863.7
Less: current portion of long-term debt			30.3				30.3
Long-term debt		$	1,826.4			$	1,833.4

Amounts drawn under the senior unsecured revolving 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. As of March 31, 2011, there were no borrowings or letters of credit outstanding under the credit facility and availability was $750.0 million.

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 March 31, 2011 and December 31, 2010 was $2,166.9 million and $2,030.2 million, respectively, which differs from the carrying amounts of $1,856.7 million and $1,863.7 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 at March 31, 2011 and December 31, 2010:

						Quoted Prices				Significant				Significant
						in				Other				Unobservable
						Active Markets				Observable Inputs				Inputs
		Total				(Level 1)				(Level 2)				(Level 3)
March 31, 2011
Derivative Financial Instruments
Foreign currency forward contracts		$	0.2			$	—			$	0.2			$	—
December 31, 2010
Derivative Financial Instruments
Foreign currency forward contracts		$	—			$	—			$	—			$	—

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 the quarter ended March 31, 2011.

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 $5.7 million at March 31, 2011.

All of our foreign currency forward contracts were accounted for as cash flow hedges under Accounting Standards Codification 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 an asset of approximately $0.2 million at March 31, 2011. 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 three months ended March 31, 2011 related to these derivative instruments.

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

		Three Months Ended
		March 31,
		2011				2010
Net unrealized gain (loss) at beginning of period		$	—			$	(0.1	)
Activity during period:
Settlement of forward contracts outstanding at beginning of period			—				—
Net unrealized gain (loss) on outstanding foreign currency forward contracts			0.2				(0.2	)
Net unrealized gain (loss) at end of period		$	0.2			$	(0.3	)

NOTE 6. INCOME TAXES

In accordance with generally accepted accounting principles, we estimate the full-year effective tax rate from continuing operations and apply this rate to our year-to-date income from continuing operations. In addition, we separately calculate the tax impact of unusual items, if any. For the three months ended March 31, 2011 and 2010, our consolidated effective tax rate for continuing operations was 8.8% and 15.4%, respectively. The lower tax rate for the 2011 period is principally the result of an increased proportion of income in lower tax jurisdictions.

NOTE 7. 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:

		Three Months Ended
		March 31,
		2011				2010
Income from continuing operations		$	30.9			$	80.7
Income from continuing operations allocated to non-vested share awards (participating securities)			(0.3	)			(0.9	)
Income from continuing operations — basic and diluted		$	30.6			$	79.8
Weighted average shares of common stock outstanding — basic			177.1				175.4
Stock options			0.8				0.5
Restricted stock awards			0.3				—
Weighted average shares of common stock outstanding — diluted			178.2				175.9
Income from continuing operations per share:
Basic		$	0.17			$	0.45
Diluted		$	0.17			$	0.45

For the three months ended March 31, 2011 and 2010, the calculation of weighted average shares of common stock outstanding — diluted excludes 0.9 million and 1.0 million, respectively, of shares of common stock issuable pursuant to outstanding stock options and certain restricted stock unit awards because their effect was anti-dilutive.

NOTE 8. 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.

During the three months ended March 31, 2011, we granted approximately 452,000 stock options, solely to our officers, at a weighted average exercise price of $32.47. The weighted average grant date fair value per share of these option awards of $11.65 was estimated using the Black-Scholes-Merton option pricing model. There were no significant changes in the weighted average assumptions used to calculate the grant date fair value of stock option awards granted during the three months ended March 31, 2011 from those used in 2010 as reported in Note 10 of our consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2010.

During the three months ended March 31, 2011, we granted approximately 744,000 restricted stock units to directors, officers and other key employees. Of those restricted stock units, approximately 485,000 units vest ratably over three years, approximately 131,000 units vest ratably over three years and contain a performance criteria that requires we have positive EBITDA during any quarter of 2011, 78,000 units cliff vest in two years and 50,000 units vested immediately. The weighted average grant date fair value per share of the restricted stock units was $33.78, $32.47, $33.89 and $32.47, respectively.

During the three months ended March 31, 2011, we also granted approximately 185,000 performance-based restricted stock units (“PRSUs”) to certain officers. The PRSUs are subject to market-based performance criteria and vest in the number of units earned over three years. The weighted average grant date fair value for the PRSUs was $29.14. The market-based performance criteria are based upon our total stockholder return measured against the total stockholder return of a representative peer group of companies.

NOTE 9. COMMITMENTS AND CONTINGENCIES

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 December 2010, 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.

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 $1.7 million, based on exchange rates as of March 31, 2011, 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 March 31, 2011, we have an accrual of $1.7 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.

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 13 of our Consolidated Financial Statements 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. On March 4, 2011, the defendants filed special exceptions alleging that plaintiffs did not have standing to bring their derivative claims on behalf of Pride because they failed to make a demand to the board of directors and failed to adequately plead demand futility. On March 23, 2011, the plaintiffs filed a second amendment to their petition alleging that our current directors also breached their fiduciary duties by failing to disclose material information or making materially inadequate disclosures concerning the proposed merger in the registration statement on Form S-4. On April 14, 2011, the Harris County District Court entered an order consolidating these actions with the Abrams and Astor lawsuits (described below) under the case styled as Ferguson v. Raspino, et al., Cause No. 2010-23805.

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 March 29, 2011, the plaintiffs filed a joint amendment to their petitions alleging that Pride’s current directors also breached their fiduciary duties by failing to disclose material information or making materially inadequate disclosures concerning the proposed merger in the registration statement on Form S-4. On April 14, 2011, the Harris County District Court entered an order consolidating these actions with the previously consolidated Ferguson and Dixon (described above) under the case styled as Ferguson v. Raspino, et al., Cause No. 2010-23805.

On February 10, 2011, Saratoga Advantage Trust, a purported stockholder of Pride, filed a class action complaint in the Delaware Court of Chancery 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 Court of Chancery. On March 1, 2011, Barry Smith, another purported stockholder of Pride, filed a substantially similar suit in the Delaware Court of Chancery. 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. On March 9, 2011, Elizabeth Wiggs-Jacques amended her complaint adding allegations that Pride’s current directors failed to disclose material information concerning the proposed merger in the registration statement on Form S-4. Also on March 9, 2011, Elizabeth Wiggs-Jacques filed a motion for preliminary injunction with a briefing schedule on the merits to be determined by the Court. On March 18, 2011, the Delaware Court of Chancery entered an order consolidating the three actions, which is captioned In re Pride International, Inc. Shareholders Litigation, Consolidated C.A. No. 6201-VCS. On April 11, 2011, the defendants filed motions to dismiss the Delaware actions with a briefing schedule on the merits to be determined by the Court. A hearing on the plaintiffs’ motion for preliminary injunction has been scheduled.

On March 8, 2011, Booth Family Trust, a purported stockholder of Pride, filed a class action complaint in U.S. District Court for the Southern District of Texas (Houston Division) requesting injunctive relief preventing the consummation of the merger, a directive to our current directors to exercise their fiduciary duties to obtain a transaction in the best interests of our stockholders and rescission of the merger agreement to the extent it has been implemented. The lawsuit alleges that the defendants violated the Exchange Act by making untrue statements of material fact and omitting to state material facts necessary to make the statements that were made in the registration statement on Form S-4 not misleading. The lawsuit further alleges that all of our current directors breached their fiduciary duties by agreeing to inadequate consideration for our stockholders and by approving the merger agreement without regard to the effect of the transaction on our stockholders. The lawsuit also alleges that we and Ensco aided and abetted the directors in the breaches of their fiduciary duties. The plaintiffs seek unspecified damages and other relief. On April 21, 2011, the defendants moved to dismiss this action and, in the alternative, requested a stay of the plaintiff’s state law claims pending the resolution of the previously filed cases in the Delaware Court of Chancery and the state courts of Harris County, Texas.

We believe that the claims stated in the complaints relating to the merger are all without merit, and we intend to defend such actions vigorously.

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 $170.5 million, based on exchange rates as of March 31, 2011. 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 $50.3 million, based on exchange rates as of March 31, 2011. On October 28, 2010, we provided credit support in satisfaction of this request. As of March 31, 2011, we have an accrual of $1.7 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, and we have filed a proof of claim in Seahawk’s bankruptcy for all damages arising from or relating to Seahawk’s repudiation of its obligations under the tax support agreement.

Other

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

In the normal course of business with customers, vendors and others, we have entered into letters of credit and surety bonds as security for certain performance obligations that totaled approximately $556.0 million at March 31, 2011, including the credit support that we have provided for the Seahawk letters of credit. These letters of credit and surety bonds are issued under a number of facilities provided by several banks and other financial institutions.

NOTE 10. 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 to consolidate our offices in France in order to reduce costs and improve operating efficiencies. The restructuring effort contemplates reallocating work to other offices, closing down one office and reducing our workforce in France. We expect the restructuring to be completed in the fourth quarter of 2011 and the associated costs to be paid using cash from operations.

The total cost of this restructuring is estimated to be approximately $20 million, net of amounts recoverable under our insurance policies, primarily related to payments to be made under ongoing and one-time termination benefit arrangements, of which $0.8 million has been accrued as of March 31, 2011 and is included in accrued expenses and other current liabilities in our consolidated balance sheet. We are required to make estimates and assumptions in calculating restructuring accruals and the details of our plan are subject to the approval of a local labor inspector. To the extent our assumptions and estimates differ from actual termination arrangements and benefits, subsequent adjustments to the accrual and total cost estimate will be required.

NOTE 11. SEGMENT AND OTHER 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 as follows:

		Three Months Ended
		March 31,
		2011				2010
Deepwater revenues:
Revenues, excluding reimbursables		$	254.9			$	217.9
Reimbursable revenues			4.2				2.9
Total Deepwater revenues			259.1				220.8
Midwater revenues:
Revenues, excluding reimbursables			98.8				93.8
Reimbursable revenues			0.5				0.4
Total Midwater revenues			99.3				94.2
Independent Leg Jackups revenues:
Revenues, excluding reimbursables			17.0				31.4
Reimbursable revenues			0.1				0.2
Total Independent Leg Jackups revenues			17.1				31.6
Other			18.0				16.2
Corporate			—				—
Total revenues		$	393.5			$	362.8
Earnings (loss) from continuing operations:
Deepwater		$	78.3			$	87.5
Midwater			8.9				30.9
Independent Leg Jackups			(7.1	)			(1.2	)
Other			(0.7	)			0.6
Corporate			(37.6	)			(31.5	)
Total		$	41.8			$	86.3
Capital expenditures:
Deepwater		$	456.1			$	490.7
Midwater			5.2				12.4
Independent Leg Jackups			4.9				8.5
Other			4.0				0.2
Corporate			3.9				4.7
Discontinued operations							0.2
Total		$	474.1			$	516.7
Depreciation:
Deepwater		$	30.5			$	20.7
Midwater			12.5				12.0
Independent Leg Jackups			8.3				7.5
Other			0.1				0.1
Corporate			1.6				1.8
Total		$	53.0			$	42.1

We measure segment assets as property and equipment. Our total long-lived assets, net, by segment as of March 31, 2011 and December 31, 2010 were as follows:

		March 31,				December 31,
		2011				2010
Total long-lived assets:
Deepwater		$	5,245.0			$	4,826.7
Midwater			709.0				716.3
Independent Leg Jackups			261.3				266.5
Other			22.2				19.0
Corporate			135.6				132.7
Total		$	6,373.1			$	5,961.2

For the three months ended March 31, 2011 and 2010, we derived 87% and 98%, respectively, of our revenues from countries outside of the United States.

Revenues, as a percentage of total consolidated revenues, from our customers for the three months ended March 31, 2011 and 2010 that contributed more than 10% of total consolidated revenues were as follows:

		Three Months Ended
		March 31,
		2011				2010
Petroleos Brasileiro S.A.			37	%			39	%
BP America and affiliates			18	%			12	%
Total S.A.			16	%			18	%
OGX Petróleo e Gás Ltda			13	%			9	%

NOTE 12. OTHER SUPPLEMENTAL INFORMATION

Supplemental cash flows and non-cash transactions were as follows:

		Three Months Ended
		March 31,
		2011				2010
Decrease (increase) in:
Trade receivables		$	(91.4	)		$	(10.0	)
Other current assets			15.0				54.3
Other assets			(1.2	)			12.7
Increase (decrease) in:
Accounts payable			12.2				(10.0	)
Accrued expenses			(25.0	)			(51.0	)
Other liabilities			1.9				(7.3	)
Net effect of changes in operating accounts		$	(88.5	)		$	(11.3	)
Cash paid during the year for:
Interest		$	47.5			$	20.7
Income taxes			6.9				6.7
Change in capital expenditures in accounts payable			(13.5	)			(10.2	)

NOTE 13. 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 mobile offshore drilling fleet. On March 1, 2011, we entered into an amendment to the merger agreement, which revised the certification, exchange and settlement procedures under the merger agreement.

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. Under certain circumstances, UK residents may receive all cash consideration as a result of compliance with legal requirements.

NOTE 14. SUBSEQUENT EVENTS

We have evaluated subsequent events through the issuance date of the unaudited consolidated financial statements and determined that there are no such events that require disclosure in this filing.

Item 2. 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 the accompanying unaudited consolidated financial statements as of March 31, 2011 and for the three months ended March 31, 2011 and 2010 included elsewhere herein, and with our annual report on Form 10-K for the year ended December 31, 2010. 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 of our annual report and elsewhere in this quarterly report. See “Forward-Looking Statements” below.

Overview

We are one of the world’s largest offshore drilling contractors. As of May 4, 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. Crude oil prices have continued to improve from the depressed level seen in February 2009 following the onset of the global financial crisis, maintaining a trading range in excess of $65 per barrel since December 2009, while averaging approximately $80 per barrel in 2010 and approximately $95 per barrel through the first quarter of 2011. We believe the sustainability of crude oil prices of $60 per barrel or higher is supportive of increased exploration and production spending by our clients, especially in the deepwater segment. The market for deepwater drilling services was characterized by uncertainty through much of 2010, due especially to the moratorium on offshore drilling in the U.S. Gulf of Mexico, as well as continued concern stemming from the global recession. The uncertainty has dissipated somewhat in early 2011, attributable in part to expanding client demand for deepwater rigs in a number of locations worldwide and the award of new drilling permits from the Bureau of Ocean Energy Management, Regulation and Enforcement of the U.S. Department of the Interior (“BOEM”) for the drilling of oil and gas prospects in the U.S. Gulf of Mexico, representing the first permits awarded for drilling in deepwater since the moratorium was lifted in October 2010. We remain confident in the long-term prospects for deepwater drilling 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 $4.3 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 rates exceeding $500,000 per day. 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 consequences stemming from the Macondo well incident, as discussed further below, could create persistent near-term uncertainty in the sector. Our contract backlog at March 31, 2011 totaled $6.2 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 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. Under certain circumstances, UK residents may receive all cash consideration as a result of compliance with legal requirements.

The merger agreement and the proposed merger are more fully described in our joint proxy statement/prospectus filed with the SEC on April 26, 2011. Please read “Risk Factors” included in Item 1A of our annual report on Form 10-K for the year ended December 31, 2010 and the joint proxy statement/prospectus 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 Deep Ocean Marquesas. The rig is based on a Samsung Heavy Industries proprietary hull design, and 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 $585 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 on or before June 15, 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 $780 million, excluding capitalized interest. Through March 31, 2011, we have spent approximately $385 million on this project. Although we currently do not have drilling contracts for the Deep Ocean Molokai and the Deep Ocean Marquesas, 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, natural disasters, 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”) early in the third 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 integrated 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 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, which was effective from August 23, 2010 until April 1, 2011. More recently, plans to relocate the rig to an alternative drilling location offshore Libya, previously identified by BP E&P for the Deep Ocean Ascension, have been cancelled due to political unrest in the region. The Deep Ocean Ascension is currently finalizing client requested modifications and waiting for BP E&P to designate the first drilling location. Subject to final documentation, we have agreed with BP E&P that the rig will remain on the special standby dayrate of $360,000 until June 1, 2011, at which time the applicable dayrate of $540,189 will begin, along with commencement of the five-year term contract.

On September 23, 2010, we took delivery of our second new ultra-deepwater drillship, the Deep Ocean Clarion. The drillship has completed its integrated acceptance testing with BP E&P in the U.S. Gulf of Mexico, the originally intended location for drilling operations, and is in the process of completing customer requested modifications and upgrades in preparation for its relocation to the first drilling location, anticipated to be outside the U.S. Gulf of Mexico. 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 commenced in early March 2011, and will continue until the earlier of July 1, 2011 or the commencement of mobilization, which is expected to begin in late-May 2011. In either event, the rig will begin earning the applicable dayrate of $596,000, per the terms of the existing contract, which has been adjusted to reflect actual operating costs and client requested capital upgrades. The five-year term will begin when operations commence at the first well location.

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.

U.S. Gulf of Mexico

In response to the April 2010 Macondo well incident in the U.S. Gulf of Mexico, the BOEM 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. Although six deepwater drilling permits have been approved for new wells by the BOEM since the moratorium was lifted in October 2010, all of which were granted in 2011, we cannot currently predict the rate at which additional 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 delays in the resumption of drilling in deepwater U.S. Gulf of Mexico that could persist through 2011.

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 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, eight 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 and in the absence of an acceleration in international rig demand, 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 covering offshore operations have increased, 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 Hercules Offshore, Inc. and its affiliate SD Drilling LLC, which agreed to pay base aggregate consideration consisting of approximately $25 million in cash and 22,321,425 shares of Hercules common stock. On April 5, 2011, Seahawk’s bankruptcy court approved the sale to Hercules, and on April 27, 2011 the asset sale was consummated. 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 Seahawk’s bankruptcy, the bankruptcy court set April 22, 2011 as the deadline for all creditors to file proofs of claim against Seahawk or any of its subsidiary chapter 11 debtors. On April 21, 2011, we timely filed three proofs of claim against Seahawk in its bankruptcy case under the various agreements that effected the separation of Seahawk from Pride and which govern the relationship between us and Seahawk after the spin-off: (1) in the amount of approximately $54.0 million, plus pre- and post-bankruptcy interest, professional fees, costs and expenses, arising under the tax support agreement described below; (2) in the amount of approximately $18.9 million, plus pre- and post-bankruptcy interest, professional fees, costs and expenses, arising under our agreements with Seahawk other than the tax support agreement; and (3) in an unspecified amount for Seahawk’s likely repudiation in its bankruptcy case of its prospective indemnification obligations to us under the various separation agreements. Duplicates of the above claims were also filed against each of Seahawk’s seven subsidiary Chapter 11 debtors. Seahawk has publicly stated its belief that it has counterclaims equal to or in excess of our claims, and it could assert such counterclaims against us in response to our proofs of claim. The parties would present evidence to the Court regarding the validity of their respective claims under relevant contractual arrangements and applicable law, and the Court would value the claims taking such evidence into account.

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 $50.3 million, based on exchange rates as of March 31, 2011. 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 and, as discussed above, we have filed a proof of claim in Seahawk’s bankruptcy for all damages arising from or relating to Seahawk’s repudiation of its 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.

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.

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 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.

Crude oil prices have maintained a trading range in excess of $65 per barrel since December 2009 and averaged approximately $80 per barrel in 2010 and approximately $95 per barrel over the first quarter of 2011. 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 and ended the first quarter of 2011 at 74%. 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. Potentially higher spending patterns, especially in deepwater, are expected to be evident in 2011 as operators continue to gain 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 $65 per barrel since late-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 and that worldwide demand for drilling rigs in the near-term has experienced marginal improvement since 2010, supported by the return to active status of eight deepwater rigs in the U.S. Gulf of Mexico during early 2011 following the award by the BOEM of the initial deepwater drilling permits since a moratorium was put in place as a result of the Macondo well incident. 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, especially in China, India and Latin America, 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 15 deepwater discoveries in 2009, operators announced 13 deepwater discoveries in 2010 covering an expanding number of offshore basins, such as Ghana, the pre-salt formation offshore Brazil, Liberia 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, Gabon, Greenland, the Falkland Islands 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 risk for an imbalance in the international deepwater rig supply in 2011 remains, caused by the potential relocation of additional units from the U.S. Gulf of Mexico as new regulations and continued delays lead to a more challenging and costly environment.

Our deepwater fleet currently operates in Brazil, West Africa and the Mediterranean Sea. As described above under “— Recent Developments,” the Deep Ocean Ascension has completed its integrated acceptance testing and is currently in the U.S. Gulf of Mexico finalizing client requested modifications and waiting for our client to designate the first drilling location. The Deep Ocean Clarion also is currently in the U.S. Gulf of Mexico and has completed its integrated acceptance testing with BP E&P and is in the process of completing customer requested modifications and upgrades in preparation for its relocation to the first drilling location in the second quarter of 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 early in the third 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 the last three quarters of 2011, with 75% in 2012, 58% in 2013, 46% in 2014, and 39% in 2015. Since an increase in customer demand for deepwater drilling rigs began in 2005, a high percentage of the industry’s deepwater fleet of 145 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 with availability in 2011 remain solidly above $400,000 per day, with recent 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.

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 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 resulted in some clients delaying decisions in 2010 on deepwater drilling requirements. These delayed contracting decisions contributed to a decline in dayrates for deepwater rigs from levels experienced in 2008 as more units competed for a reduced number of contract opportunities. However, with evidence of increasing demand in several regions and the early stages of recovery in activity in the U.S. Gulf of Mexico, utilization and dayrates for the industry’s most technologically advanced rigs is expected to improve in 2011. The risk of lower utilization and dayrates is 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 15 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 and that dayrates could improve modestly in the near-term for several reasons, including the need for additional units in Brazil to address the exploration and development programs associated with the pre-salt formation, the commencement of an increased number of projects, especially in the emerging locations around the world, and higher trending crude oil prices, which support higher exploration and spending by our clients as their confidence regarding the sustainability of crude oil prices improves. A risk to strengthening utilization and continued dayrate improvement is the increase in deepwater drilling capacity through 2013, when as many as 33 uncommitted new deepwater rigs are expected to complete construction programs and enter the active global fleet. Many of the 33 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. We also believe, with deepwater drilling rigs returning to work in the U.S. Gulf of Mexico as drilling permit approvals are secured, fewer rigs will choose to relocate to international locations, reducing the possibility of lower dayrates and utilization in some international locations. As of March 31, 2011, eight deepwater rigs in the U.S. Gulf of Mexico have relocated or have been identified for relocation to other regions with additional relocations possible.

In the first quarter of 2011, new orders for 19 deepwater rigs have been placed by seven contractors with expected deliveries beginning in 2013 and continuing through 2018. 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.

Our Midwater segment consists of six semisubmersible rigs. Five of the rigs currently operate offshore Brazil, while the sixth rig, the Pride South Seas, is in the process of being reactivated for service in order to address a recently awarded contract that is expected to commence in the third quarter of 2011. We currently have 82% of our available rig days contracted for our midwater fleet in the last three quarters of 2011, with 35% in 2012, 14% in 2013 and none in 2014. Utilization of the industry’s midwater fleet was 82% at March 31, 2011, with 21 rigs idle around the world compared to utilization of 89% at the same time in 2010, when 13 rigs were idle. The economic instability and uncertainty in crude oil markets, along with persistent weakness in the deepwater rig segment, contributed to a growing number of inactive midwater rigs in 2010 and this more challenging environment has continued into 2011. With Brent crude oil prices averaging $80 per barrel in 2010 and approximately $105 per barrel over the first quarter of 2011, midwater activity and dayrates in the U.K. and Norwegian sectors of the North Sea have remained steady to modestly higher. Outside of the North Sea, activity in 2011 is expected to improve in West Africa, Brazil and the Far East, although the availability of conventionally moored deepwater rigs in these regions is expected to continue to threaten a potential recovery 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. In addition, midwater rigs, as well as conventionally moored deepwater rigs, have experienced lower client appeal in the U.S. Gulf of Mexico 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, resulting in an increasing number of the units relocating to international locations. 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 consists of seven rigs, two of which are currently operating in the Middle East, one in West Africa and four others are currently without contracts with limited prospects for work in 2011. We currently have 28% of our available rig days contracted for our independent leg jackup fleet in the last three quarters of 2011, with 14% contracted in 2012 and 2013, and none in 2014. 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. Through early 2011, activity levels remain depressed for the industry’s standard capability rigs, while high specification jackups are benefiting from strong customer preference, leading to improved utilization and dayrates. As of March 31, 2011, 100 independent leg jackup rigs were idle in the global fleet out of a total fleet of 417, representing segment utilization of 76% compared to 79% at March 31, 2010. The majority of the idle rigs have been in service over 25 years and have less advanced operating specifications. 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, 91 jackup rigs have been added to the global fleet, with another 63 rigs expected to be added by the end of 2013. These new rigs are largely equipped with high specification features and capabilities, including greater hook loads, extended cantilever reach, advanced drilling depths 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. Utilization of these advanced rigs exceeded 85% at March 31, 2011. 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 105 out-of-service days for shipyard maintenance and upgrade projects for the three months ended March 31, 2011 for our existing fleet as compared to approximately 180 days for the three months ended March 31, 2010. For 2011, we expect the total number of out-of-service days to be approximately 470 as compared to 730 days for 2010. The decline in expected out-of-service days in 2011 is primarily due to a reduction of planned shipyard construction projects in our Midwater and Independent Leg Jackup segments.

Backlog

Our contracted backlog at March 31, 2011 totaled approximately $6.2 billion for our executed contracts. We expect approximately $1.7 billion of our total backlog to be realized in the next 12 months. Our backlog at December 31, 2010 was approximately $6.4 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 March 31, 2011. 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(1)				2012				2013				2014
Rig Days Committed
Deepwater			85%				75%				58%				46%
Midwater			82%				35%				14%				0%
Independent Leg Jackups			28%				14%				14%				0%

Segment Review

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

		Three Months Ended
		March 31,
		2011				2010
		(In millions)
Deepwater revenues:
Revenues, excluding reimbursables		$	254.9			$	217.9
Reimbursable revenues			4.2				2.9
Total Deepwater revenues			259.1				220.8
Midwater revenues:
Revenues, excluding reimbursables			98.8				93.8
Reimbursable revenues			0.5				0.4
Total Midwater revenues			99.3				94.2
Independent Leg Jackups revenues:
Revenues, excluding reimbursables			17.0				31.4
Reimbursable revenues			0.1				0.2
Total Independent Leg Jackups revenues			17.1				31.6
Other			18.0				16.2
Corporate			—				—
Total revenues		$	393.5			$	362.8
Earnings (loss) from continuing operations:
Deepwater		$	78.3			$	87.5
Midwater			8.9				30.9
Independent Leg Jackups			(7.1	)			(1.2	)
Other			(0.7	)			0.6
Corporate			(37.6	)			(31.5	)
Total		$	41.8			$	86.3

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

		Three Months Ended March 31,
		2011								2010
		Average								Average
		Daily				Utilization				Daily				Utilization
		Revenues (1)				(2)				Revenues (1)				(2)
Deepwater		$	341,400				91	%		$	335,100				91	%
Midwater		$	255,200				72	%		$	265,000				66	%
Independent Leg Jackups		$	98,800				27	%		$	110,100				45	%

Deepwater

Revenues for our Deepwater segment increased $38.3 million, or 17%, for the three months ended March 31, 2011 over the comparable period in 2010. 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, and the Deep Ocean Clarion, which was placed on a special standby dayrate of $380,000 beginning in March 2011. The increase is also due to the Pride Carlos Walter and Pride Rio de Janeiro, which experienced higher utilization in the first quarter of 2011 over the comparable period in 2010. These factors contributed to an increase in revenues of $54.6 million over 2010. The increase in revenues was partially offset by the Pride North America, which operated at a lower dayrate, in addition to experiencing increased downtime in the first quarter of 2011 related to a water-depth upgrade performed in advance of commencing its new contract, certain unscheduled repairs and delays caused by civil unrest in Egypt, and the Pride Brazil, which commenced a shipyard project mid-March 2011 that lasted approximately 40 days. Together, these factors resulted in a $16.0 million decrease in revenues in the first quarter of 2011 over the comparable period in 2010. Average daily revenues increased 2% for the three months ended March 31, 2011 over the comparable period in 2010 primarily due to the higher dayrate earned by the Pride Portland and the commencement of the special standby dayrates of the Deep Ocean Ascension and the Deep Ocean Clarion, partially offset by the decreased dayrate for the Pride North America. Earnings from operations decreased $9.2 million, or 11%, for the three months ended March 31, 2011 over the comparable period in 2010 primarily due to the lower utilization of the Pride North America and the Pride Brazil described above, increased labor costs for our offshore workforce and start-up costs associated with the Deep Ocean Mendocino, partially offset by the increased revenue due to special standby dayrates for the Deep Ocean Ascension and the Deep Ocean Clarion and the increased utilization of the Pride Carlos Walter and Pride Rio de Janeiro. Utilization remained unchanged at 91% for the three months ended March 31, 2011 and 2010.

Midwater

Revenues for our Midwater segment increased $5.1 million, or 5%, for the three months ended March 31, 2011 over the comparable period in 2010. The increase in revenues is primarily due to the Pride Venezuela, which was fully utilized in the first quarter of 2011 compared to the first quarter of 2010 during which the rig was in the shipyard for a rig refurbishment project. The resulting increase in utilization of this rig contributed to an increase in revenues of $23.9 million over the comparable period in 2010. This increase in revenues was substantially offset by the Pride South Atlantic, which underwent certain unscheduled repairs to the BOP control pods and stack mounted equipment, as well as non-equipment related work performed to remediate non-conformities identified in connection with a regulatory inspection in the first quarter of 2011, which resulted in 52 days of downtime, and the Sea Explorer, which operated at a lower dayrate in the first quarter of 2011 over the comparable period in 2010. These factors contributed to an $18.7 million decrease in revenues in the first quarter of 2011 over 2010. Average daily revenues decreased 4% for the three months ended March 31, 2011 over the comparable period in 2010 primarily due to the lower dayrate earned by the Sea Explorer. Earnings from operations decreased $22.0 million, or 71%, for the three months ended March 31, 2011 over the comparable period in 2010 primarily due to the decreased utilization of the Pride South Atlantic, the decreased dayrate earned by the Sea Explorer, increased labor costs across the fleet, increased repair and maintenance costs for certain rigs, and increased costs associated with the amortization of deferred mobilization charges for the Pride Venezuela, partially offset by the increased utilization of the Pride Venezuela. Utilization increased to 72% for the three months ended March 31, 2011 from 66% for the three months ended March 31, 2010 primarily due to the increased utilization of the Pride Venezuela, partially offset by the decreased utilization of the Pride South Atlantic.

Independent Leg Jackup

Revenues for our Independent Leg Jackup segment decreased $14.5 million, or 46%, for the three months ended March 31, 2011 over the comparable period in 2010. The decrease in revenues is primarily due to the Pride Hawaii, which has remained cold-stacked since the second quarter of 2010 following the completion of a three year contract, and the Pride Cabinda, which experienced an incremental 23 out-of-service days during the first quarter of 2011 while awaiting the commencement of its new contract. These factors contributed to a $15.7 million decrease in revenues for the three months ended March 31, 2011 over the comparable period in 2010. This decrease in revenues was partially offset by the Pride Montana, which contributed an incremental $2.2 million of revenues during the first quarter of 2011 as a result of higher utilization. Average daily revenues decreased 10% for the three months ended March 31, 2011 over the comparable period in 2010 primarily due to the Pride Hawaii, which was under contract during the first quarter of 2010 prior to being cold-stacked, and the Pride Cabinda, which operated at a lower dayrate in the first quarter of 2011 over the comparable period in 2010. Earnings from operations decreased $5.9 million to a loss of $7.1 million for the three months ended March 31, 2011 compared with a loss of $1.2 million for the three months ended March 31, 2010 primarily due to the Pride Hawaii being cold-stacked and the out-of-service days for the Pride Cabinda, and the Pride North Dakota, which experienced increased costs associated with preparing the rig to commence a new contract in the first quarter of 2011. These decreases in earnings were partially offset by a reduction in operating costs for the Pride Hawaii. Utilization decreased to 27% for the three months ended March 31, 2011 from 45% for the three months ended March 31, 2010, primarily due to lower utilization of the Pride Hawaii and Pride Cabinda.

Other Operations

Other operations include our deepwater drilling operations management contracts and other operating activities. Our management contracts include two contracts which expire in 2012 and 2015 (with early termination permitted in certain cases).

Revenues increased $1.8 million, or 11%, for the three months ended March 31, 2011 over the comparable period in 2010 primarily due to the commencement of a new management contract in April 2010 at a higher dayrate. Earnings from operations decreased $1.3 million to a loss of $0.7 million for the three months ended March 31, 2011 compared with earnings of $0.6 million for the three months ended March 31, 2010, primarily due to increased labor costs.

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:

		Three Months Ended
		March 31,
		2011				2010
		(In millions)
REVENUES
Revenues, excluding reimbursable revenues		$	386.1			$	357.4
Reimbursable revenues			7.4				5.4
			393.5				362.8
COSTS AND EXPENSES
Operating costs, excluding depreciation			256.7				200.9
Reimbursable costs			6.5				4.2
Depreciation			53.0				42.1
General and administrative			35.5				29.5
Gain on sales of assets, net			—				(0.2	)
			351.7				276.5
EARNINGS FROM OPERATIONS			41.8				86.3
OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized			(4.7	)			—
Interest income			0.6				0.2
Other income (expense), net			(3.8	)			8.9
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES			33.9				95.4
INCOME TAXES			(3.0	)			(14.7	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX		$	30.9			$	80.7

Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010

Revenues Excluding Reimbursable Revenues. Revenues, excluding reimbursable revenues for the three months ended March 31, 2011 increased $28.7 million, or 8%, over the comparable period in 2010. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for the three months ended March 31, 2011 increased $2.0 million, or 37%, over the comparable period in 2010, primarily due to increased reimbursable revenue related to operation of the Deep Ocean Ascension, the Pride Africa and the Pride Angola, partially offset by decreased reimbursable revenue related to the operation of the Sea Explorer.

Operating Costs. Operating costs for the three months ended March 31, 2011 increased $55.8 million, or 28%, over the comparable period in 2010. The increase is largely attributable to $22.6 million of increased operating costs resulting from the Deep Ocean Ascension and Deep Ocean Clarion, which went on special standby dayrates in August 2010 and March 2011, respectively, and increased startup costs for the recently delivered Deep Ocean Mendocino. Additionally, we experienced an increase of $17.8 million in labor and materials and supplies costs, excluding our newbuild drillships, increased costs totaling $14.4 million due to the return to full operations by the Pride Venezuela, which was in the shipyard in the first quarter of 2010, and an increase of $5.0 million associated with the repairs to the Pride South Atlantic that were performed in the first quarter of 2011. Partially offsetting these increases were reductions in operating costs totaling $9.4 million which resulted from lower activity in our Independent Leg Jackup segment.

Reimbursable Costs. Reimbursable costs for the three months ended March 31, 2011 increased $2.3 million, or 55%, over the comparable period in 2010 primarily due to higher reimbursable costs in our Deepwater and Other Segments.

Depreciation. Depreciation expense for the three months ended March 31, 2011 increased $10.9 million, or 26%, over the comparable period in 2010. This increase relates primarily to the capital additions in our Deepwater and Midwater segments, including the impact associated with the commencement of depreciation on the Deep Ocean Ascension in August 2010 and the Deep Ocean Clarion in March 2011.

General and Administrative. General and administrative expenses for the three months ended March 31, 2011 increased $6.0 million, or 20%, over the comparable period in 2010 primarily due to $7.7 million of transaction related costs associated with the proposed merger with Ensco, partially offset by $1.3 million of lower expenses related to the investigation described under “—FCPA Investigation” and $1.0 million of lower labor costs.

Interest Expense. We had $4.7 million of interest expense for the three months ended March 31, 2011 and no interest expense for the three months ended March 31, 2010, excluding capitalized interest of $31.2 million and $23.0 million for the three months ended March 31, 2011 and 2010, respectively. Total interest incurred for the three months ended March 31, 2011 increased over the comparable period in 2010 due to an increase in our average total debt balances outstanding in the 2011 period resulting from the issuance of our 6 7/8% senior notes due 2020 and our 7 7/8% senior notes due 2040, offset by the redemption of our 7 3/8% senior notes due 2014, in the third quarter of 2010.

Other Income (Expense), Net. Other income (expense), net for the three months ended March 31, 2011 decreased $12.7 million to an expense of $3.8 million from income of $8.9 million for the comparable period in 2010 primarily due to foreign exchange losses in the first quarter of 2011 and foreign exchange gains in the comparable 2010 period.

Income Taxes. Our consolidated effective income tax rate for continuing operations for the three months ended March 31, 2011 was 8.8% compared with 15.4% for the three months ended March 31, 2010. The lower tax rate for the 2011 period is principally the result of an increased proportion of income in lower tax jurisdictions.

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 March 31, 2011 was $1.9 billion, and stockholders’ equity was $4.6 billion, resulting in a debt-to-total-capital ratio of 29%.

During the first quarter of 2011, we used cash on hand, the remaining net proceeds from the August 2010 notes offering, and cash flows from operations as our primary source of liquidity for funding our working capital needs, debt repayment and capital expenditures. We believe that our cash on hand, 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 quarterly 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.

Sources and Uses of Cash

Cash flows from operating activities

Cash flows from operating activities were $16.1 million for the three months ended March 31, 2011 compared with $100.2 million for the comparable period in 2010. The decrease of $84.1 million was primarily due to a reduction of income from continuing operations, a larger increase in our trade receivables than in the comparable prior quarter, and changes in our other operating assets and liabilities.

Cash flows used in investing activities

Cash flows used in investing activities were $474.1 million for the three months ended March 31, 2011 compared with $516.3 million for the comparable period in 2010, a decrease of $42.2 million. The decrease is primarily attributable to a decrease in expenditures incurred towards the construction of our ultra-deepwater drillships due to the completion and delivery of the Deep Ocean Clarion and the Deep Ocean Mendocino in September 2010 and January 2011, respectively.

Cash flows from financing activities

Cash flows from financing activities were $18.8 million for the three months ended March 31, 2011 compared with cash flows used in financing activites of $0.2 million for the comparable period in 2010, an increase of $19.0 million. The increase in cash flows from financing activities was primarily due to an increase of $21.6 million in net proceeds from employee stock transactions, which totaled $25.9 million and $4.3 million for the three months ended March 31, 2011 and 2010, respectively. Cash used for scheduled debt repayments totaled $7.1 million for the three months ended March 31, 2011 and 2010.

Working Capital

As of March 31, 2011, we had working capital of $111.0 million compared with $463.1 million as of December 31, 2010. The decrease in working capital is primarily due to expenditures of approximately $370 million incurred towards the construction of our ultra-deepwater drillships.

Revolving Credit Facility

We have a $750 million unsecured revolving credit agreement with a group of banks maturing in July 2013. 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. Amounts drawn under the credit facility 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 interest rate margin applicable to LIBOR advances varies based on our credit rating. As of March 31, 2011, there were no outstanding borrowings or letters of credit outstanding under the facility.

Other Outstanding Debt

As of March 31, 2011, in addition to our credit facility, we had the following long-term debt, including current maturities, outstanding:

	•		$500.0 million principal amount of 8 1/2% senior notes due 2019;
	•		$900.0 million principal amount of 6 7/8% senior notes due 2020;
	•		$300.0 million principal amount of 7 7/8% senior notes due 2040; and
	•		$159.6 million principal amount of notes guaranteed by the United States Maritime Administration.

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 $239 million, of which we have spent approximately $63 million in the first three months. 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 reactivation of rigs which were previously taken out of service, along with other sustaining capital projects. With respect to our drillship construction projects, we made payments of $338 million in the first three months of 2011, with the total remaining 2011 costs, including remaining costs related to the Deep Ocean Molokai, estimated to be approximately $425 million. We anticipate making additional payments for the construction of our drillships of approximately $130 million in 2012 and approximately $370 million in 2013. 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, cash flow from operations and, if needed, borrowings under our revolving credit facility.

We anticipate making income tax payments of approximately $40 million to $45 million in 2011, of which $6.9 million has been paid through March 31, 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.

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 to consolidate our offices in France, in order to reduce costs and improve operating efficiencies. The restructuring effort contemplates reallocating work to other offices, closing down one office and reducing our workforce in France. We expect the restructuring to be completed in the fourth quarter of 2011 and the associated costs to be paid using cash from operations. We estimate that the total cost of the restructuring will be approximately $20 million, net of amounts recoverable under our insurance policies; however, to the extent our assumptions and estimates differ from actual termination arrangements or the time period necessary to complete the restructuring, subsequent adjustments to our cost estimate may be required.

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

Letters of Credit

We are contingently liable as of March 31, 2011 in the aggregate amount of $556.0 million under certain performance, bid and custom bonds and letters of credit, including the credit support that we have provided for the Seahawk letters of credit. As of March 31, 2011, we had not been required to make any collateral deposits with respect to these agreements.

Contractual Obligations

For additional information about our contractual obligations as of December 31, 2010, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Contractual Obligations” in Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2010. As of March 31, 2011, there were no material changes to this disclosure regarding our contractual obligations made in the annual report.

Forward-Looking Statements

This quarterly 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 quarterly 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;
	•		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.

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, in “Risk Factors” in Item 1A of our annual report on Form 10-K for the year ended December 31, 2010 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 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 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposure to interest rate risks, see “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of our annual report on Form 10-K for the year ended December 31, 2010. There have been no material changes to the disclosure regarding our exposure to certain market risks made in the annual report.

For additional information regarding our long-term debt, see Note 4 of our Notes to Unaudited Consolidated Financial Statements included in Item 1 of Part I of this quarterly report.

Item 4. Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this quarterly 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 March 31, 2011 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.

There were no changes in our internal control over financial reporting that occurred during the first quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

The information set forth in Note 9 of our Notes to Unaudited Consolidated Financial Statements included in Item 1 of Part I of this quarterly report is incorporated by reference in response to this item.

Item 1A. Risk Factors

For additional information about our risk factors, see Item 1A of our annual report on Form 10-K for the year ended December 31, 2010.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table presents information regarding our repurchases of shares of our common stock on a monthly basis during the first quarter of 2011:

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)

January 1-31, 2011

162,997

$

32.78

N/A

N/A

February 1-28, 2011

2,812

$

39.56

N/A

N/A

March 1-31, 2011

642

$

42.36

N/A

N/A

Total

166,451

$

32.93

N/A

N/A

Item 6. Exhibits***

	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			Amendment to Agreement and Plan of Merger, dated March 1, 2011, by and among Pride, Ensco, ENSCO International Incorporated and ENSCO Ventures LLC (incorporated by reference to Exhibit 2.2 to the Registration Statement of Ensco plc on Form S-4 filed with the SEC on March 3, 2011, File No. 333-172587).
	12	*		Computation of Ratio of Earnings to Fixed Charges.
	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 and 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.CAL		**		XBRL Taxonomy Extension Calculation Linkbase
101.LAB		**		XBRL Taxonomy Extension Label Linkbase
101.PRE		**		XBRL Taxonomy Extension Presentation Linkbase
101.DEF		**		XBRL Taxonomy Extension Definition Linkbase

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: May 5, 2011

Date: May 5, 2011

INDEX TO EXHIBITS

	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			Amendment to Agreement and Plan of Merger, dated March 1, 2011, by and among Pride, Ensco, ENSCO International Incorporated and ENSCO Ventures LLC (incorporated by reference to Exhibit 2.2 to the Registration Statement of Ensco plc on Form S-4 filed with the SEC on March 3, 2011, File No. 333-172587).
	12	*		Computation of Ratio of Earnings to Fixed Charges.
	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 and 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.CAL		**		XBRL Taxonomy Extension Calculation Linkbase
101.LAB		**		XBRL Taxonomy Extension Label Linkbase
101.PRE		**		XBRL Taxonomy Extension Presentation Linkbase
101.DEF		**		XBRL Taxonomy Extension Definition Linkbase