10-Q

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

For the quarterly period ended June 30, 2010

Or

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
	July 26, 2010
Common Stock, par value $.01 per share	175,646,791

Table of Contents

	Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements		3
Consolidated Balance Sheets — June 30, 2010 and December 31, 2009		3
Consolidated Statements of Operations — Three and Six months ended June 30, 2010 and 2009.		4
Consolidated Statements of Cash Flows — Six months ended June 30, 2010 and 2009		6
Notes to Unaudited Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 3. Quantitative and Qualitative Disclosures About Market Risk		43
Item 4. Controls and Procedures		43
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		43
Item 1A. Risk Factors		43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		45
Item 6. Exhibits		46
Signatures		47
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

2

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Pride International, Inc.

Consolidated Balance Sheets
(In millions, except par value)

	June 30,			December 31,
	2010			2009
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	311.0		$	763.1
Trade receivables, net		201.2			211.9
Deferred income taxes		8.5			21.6
Other current assets		115.5			167.6
Total current assets		636.2			1,164.2
PROPERTY AND EQUIPMENT		6,760.5			6,091.0
Less: accumulated depreciation		1,280.8			1,200.7
Property and equipment, net		5,479.7			4,890.3
OTHER ASSETS, NET		76.7			88.4
Total assets	$	6,192.6		$	6,142.9
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	30.3		$	30.3
Accounts payable		139.6			132.4
Accrued expenses and other current liabilities		277.0			339.7
Total current liabilities		446.9			502.4
OTHER LONG-TERM LIABILITIES		109.3			118.3
LONG-TERM DEBT, NET OF CURRENT PORTION		1,147.0			1,161.7
DEFERRED INCOME TAXES		84.1			102.7
STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value; 50.0 shares authorized; none issued		—			—
Common stock, $0.01 par value; 400.0 shares authorized; 176.6 and 175.5 shares issued; 175.6 and 174.6 shares outstanding		1.8			1.8
Paid-in capital		2,082.4			2,058.7
Treasury stock, at cost; 1.1 and 0.9 shares		(21.5	)		(16.4	)
Retained earnings		2,341.2			2,210.8
Accumulated other comprehensive income		1.4			2.9
Total stockholders’ equity		4,405.3			4,257.8
Total liabilities and stockholders’ equity	$	6,192.6		$	6,142.9

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

3

Pride International, Inc.

Consolidated Statements of Operations
(Unaudited)
(In millions, except per share amounts)

	Three Months Ended
	June 30,
	2010			2009
REVENUES
Revenues excluding reimbursable revenues	$	344.0		$	434.4
Reimbursable revenues		6.3			5.1
		350.3			439.5
COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		217.9			205.2
Reimbursable costs		5.1			4.6
Depreciation and amortization		44.7			39.3
General and administrative, excluding depreciation and amortization		25.5			26.1
Gain on sales of assets, net		(0.2	)		—
		293.0			275.2
EARNINGS FROM OPERATIONS		57.3			164.3
OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		—			(0.1	)
Interest income		0.9			0.7
Other income (expense), net		2.6			(3.6	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		60.8			161.3
INCOME TAXES		(3.1	)		(26.6	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX		57.7			134.7
LOSS FROM DISCONTINUED OPERATIONS, NET OF TAX		(0.2	)		(10.6	)
NET INCOME	$	57.5		$	124.1
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	0.32		$	0.76
Loss from discontinued operations		—			(0.06	)
Net income	$	0.32		$	0.70
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	0.32		$	0.76
Loss from discontinued operations		—			(0.06	)
Net income	$	0.32		$	0.70
SHARES USED IN PER SHARE CALCULATIONS
Basic		175.5			173.5
Diluted		176.0			173.7

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

4

Pride International, Inc.
Consolidated Statements of Operations
(Unaudited)
(In millions, except per share amounts)

	Six Months Ended
	June 30,
	2010			2009
REVENUES
Revenues excluding reimbursable revenues	$	701.4		$	873.7
Reimbursable revenues		11.7			17.7
		713.1			891.4
COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		418.8			405.4
Reimbursable costs		9.4			15.8
Depreciation and amortization		86.8			78.8
General and administrative, excluding depreciation and amortization		55.1			55.2
Gain on sales of assets, net		(0.5	)		(0.5	)
		569.6			554.7
EARNINGS FROM OPERATIONS		143.5			336.7
OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		—			(0.1	)
Interest income		1.1			2.1
Other income (expense), net		11.6			(0.6	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		156.2			338.1
INCOME TAXES		(17.8	)		(54.5	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX		138.4			283.6
LOSS FROM DISCONTINUED OPERATIONS, NET OF TAX		(7.9	)		(0.6	)
NET INCOME	$	130.5		$	283.0
BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	0.78		$	1.61
Loss from discontinued operations		(0.05	)		—
Net income	$	0.73		$	1.61
DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	0.78		$	1.61
Loss from discontinued operations		(0.05	)		—
Net income	$	0.73		$	1.61
SHARES USED IN PER SHARE CALCULATIONS
Basic		175.5			173.4
Diluted		176.0			173.5

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

5

Pride International, Inc.

Consolidated Statements of Cash Flows
(Unaudited)
(In millions)

	Six Months Ended
	June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	130.5		$	283.0
Adjustments to reconcile net income to net cash from operating activities:
Gain on sale of Eastern Hemisphere land rigs		—			(5.4	)
Depreciation and amortization		86.8			107.9
Amortization and write-offs of deferred financing costs		1.2			0.9
Amortization of deferred contract liabilities		(26.9	)		(26.9	)
Gain on sales of assets, net		(0.5	)		(5.4	)
Deferred income taxes		(2.9	)		(5.4	)
Excess tax benefits from stock-based compensation		(2.6	)		(0.1	)
Stock-based compensation		16.5			17.9
Other, net		0.5			0.4
Net effect of changes in operating accounts (See Note 12)		4.0			0.8
Change in deferred gain on asset sales and retirements		—			4.9
Increase (decrease) in deferred revenue		0.6			(9.1	)
Decrease in deferred expense		3.2			11.1
NET CASH FLOWS FROM OPERATING ACTIVITIES		210.4			374.6
CASH FLOWS USED IN INVESTING ACTIVITIES:
Purchases of property and equipment		(655.4	)		(474.7	)
Proceeds from dispositions of property and equipment		0.9			0.8
Proceeds from the sale of Eastern Hemisphere land rigs, net		—			9.6
Proceeds from insurance		—			13.9
NET CASH FLOWS USED IN INVESTING ACTIVITIES		(654.5	)		(450.4	)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Repayments of borrowings		(15.2	)		(15.2	)
Proceeds from debt borrowings		—			498.2
Debt financing costs		(0.1	)		(6.0	)
Net proceeds from employee stock transactions		4.7			1.9
Excess tax benefits from stock-based compensation		2.6			0.1
NET CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES		(8.0	)		479.0
(Decrease) increase in cash and cash equivalents		(452.1	)		403.2
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		763.1			712.5
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	311.0		$	1,115.7

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

6

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 24 offshore rigs. We also have three deepwater drillships under construction.

Basis of Presentation

In August 2009, we completed the spin-off of Seahawk Drilling, Inc., which holds the assets and liabilities that were associated with our 20-rig mat-supported jackup business. The results of operations, for all periods presented, of the assets disposed of in this transaction have been reclassified to loss from discontinued operations. Except where noted, the discussions in the following notes relate to our continuing operations only (see Note 2).

Our unaudited consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. 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, 2009. 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. Actual results could differ from those estimates.

Property and Equipment

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

We evaluate our property and equipment for impairment whenever events or changes in circumstances indicate the carrying value of such assets or asset groups may not be recoverable. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets and could materially affect our results of operations.

During the second quarter of 2010, management determined that a triggering event had occurred for the Independent Leg Jackup asset group as of June 30, 2010. The triggering event resulted from current and forecasted operating losses within the asset group. Management performed an undiscounted cash flow analysis for the group’s long-lived assets to determine if there was any impairment of the asset group. The assessment indicated that undiscounted cash flows for the asset group exceeded its carrying value by $134.2 million, as of June 30, 2010. Therefore, the asset group is not impaired.

7

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

Fair Value Accounting

We use fair value measurements to record fair value adjustments to certain financial and nonfinancial assets and liabilities and to determine fair value disclosures. Our foreign currency forward contracts are recorded at fair value on a recurring basis. See Note 5 — Fair Value Measurements.

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

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

Comprehensive Income

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010			2009
Net Income	$	57.5	$	124.1	$	130.5		$	283.0
Other comprehensive gains (losses), net of tax
Foreign currency translation		0.5		1.8		(0.1	)		1.8
Foreign currency hedges, net of tax		—		0.2		(0.2	)		0.2
Defined benefit plan		—		—		(1.2	)		—
Comprehensive Income	$	58.0	$	126.1	$	129.0		$	285.0

Accounting Pronouncements

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

8

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

In April 2010, the FASB issued ASU 2010-17, Milestone Method of Revenue Recognition, a consensus of the FASB Emerging Issues Task Force. This update provides guidance on defining a milestone and determining when it may be appropriate to apply the milestone method of revenue recognition for research or development transactions. Consideration that is contingent on achievement of a milestone in its entirety may be recognized as revenue in the period in which the milestone is achieved only if the milestone is judged to meet certain criteria to be considered substantive. Milestones should be considered substantive in their entirety and may not be bifurcated. An arrangement may contain both substantive and nonsubstantive milestones that should be evaluated individually. ASU 2010-17 is effective on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after June 15, 2010. We adopted the update as of July 1, 2010. The update will have no effect on our consolidated financial position, results of operations or cash flows as we currently have no research or development transactions.

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

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 being distinguishable from the rest of our company because it has clearly distinguished operations and cash flows. A component may be a reportable segment, an operating segment, a reporting unit, a subsidiary, or an asset group. Such reclassifications had no effect on our net income or stockholders’ equity.

Spin-off of Mat-Supported Jackup Business

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues	$	—		$	61.2		$	—		$	158.6
Loss before taxes		(0.3	)		(17.7	)		(0.8	)		(5.8	)
Income taxes		0.1			4.8			0.3			0.5
Loss from discontinued operations	$	(0.2	)	$	(12.9	)	$	(0.5	)	$	(5.3	)

9

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.

Other Divestitures

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

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

During the third quarter of 2007, we completed the disposition of our Latin America Land and E&P Services segments for $1.0 billion in cash. The purchase price was subject to certain post-closing adjustments for working capital and other indemnities. In December 2009, we filed suit against the buyer in the federal district court in the Southern District of New York to collect the final amount of the working capital adjustment payable by the buyer to us, plus interest, as determined in accordance with the purchase agreement, and the buyer made various counterclaims in the proceeding. All claims of the parties were settled in the first quarter of 2010, and the federal district court dismissed the claims with prejudice on March 10, 2010. From the closing date of the sale in the third quarter of 2007 through June 30, 2010, we recorded a total gain on disposal of $318.6 million, which included certain valuation adjustments for tax and other indemnities provided to the buyer and selling costs incurred by us. We have indemnified the buyer for certain obligations that may arise or be incurred in the future by the buyer with respect to the business. We believe it is probable that some of these indemnified liabilities will be settled with the buyer in cash. Our total estimated gain on disposal of assets includes a $1.8 million liability based on our fair value estimates for the indemnities. 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:

	June 30,			December 31,
	2010			2009
Rigs and rig equipment	$	4,221.5		$	4,101.4
Construction-in-progress — newbuild drillships		2,181.8			1,682.4
Construction-in-progress — other		276.2			222.8
Other		81.0			84.4
Property and equipment, cost		6,760.5			6,091.0
Accumulated depreciation and amortization		(1,280.8	)		(1,200.7	)
Property and equipment, net	$	5,479.7		$	4,890.3

10

NOTE 4. DEBT

Debt consisted of the following:

	June 30,		December 31,
	2010		2009
Senior unsecured revolving credit facility	$	—	$	—
8 1/2% Senior Notes due 2019, net of unamortized discount of $1.7 million and $1.7 million, respectively		498.3		498.3
7 3/8% Senior Notes due 2014, net of unamortized discount of $1.3 million and $1.4 million, respectively		498.7		498.6
MARAD notes, net of unamortized fair value discount of $1.6 million and $1.9 million, respectively		180.3		195.1
Total debt		1,177.3		1,192.0
Less: current portion of long-term debt		30.3		30.3
Long-term debt	$	1,147.0	$	1,161.7

Amounts drawn under the senior unsecured revolving credit facility bear interest at variable rates based on LIBOR plus a margin or the alternative base rate as defined in the agreement. The interest rate margin applicable to LIBOR advances varies based on our credit rating. As of June 30, 2010, there were no borrowings or letters of credit outstanding under the facility and availability was $320.0 million.

NOTE 5. FAIR VALUE MEASUREMENTS

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 June 30, 2010 and December 31, 2009 was $1,225.6 million and $1,307.6 million, respectively, which differs from the carrying amounts of $1,177.3 million and $1,192.0 million, respectively, included in our consolidated balance sheets. The fair value of our debt has been estimated based on quarter- and year-end quoted market prices.

The following table presents our financial liabilities measured at fair value on a recurring basis at June 30, 2010 and December 31, 2009:

				Quoted Prices		Significant			Significant
				in		Other			Unobservable
				Active Markets		Observable Inputs			Inputs
	Total			(Level 1)		(Level 2)			(Level 3)
June 30, 2010
Derivative Financial Instruments
Foreign currency forward contracts	$	(0.3	)	$	—	$	(0.3	)	$	—
December 31, 2009
Derivative Financial Instruments
Foreign currency forward contracts	$	(0.1	)	$	—	$	(0.1	)	$	—

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.

11

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 June 30, 2010.

NOTE 6. DERIVATIVES AND FINANCIAL INSTRUMENTS

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 $5.1 million at June 30, 2010.

All of our foreign currency forward contracts were accounted for as cash flow hedges under ASC Topic 815, Derivatives and Hedging. The fair market value of these derivative instruments is included in other current assets or accrued expenses and other current liabilities, with the cumulative unrealized gain or loss included in accumulated other comprehensive income in our consolidated balance sheet. The payroll and related costs that are being hedged are included in accrued expenses and other current liabilities in our consolidated balance sheet, with the realized gain or loss associated with the revaluation of these liabilities from euros to U.S. dollars included in other income (expense). Amounts recorded in accumulated other comprehensive income associated with the derivative instruments are subsequently reclassed into other income (expense) as earnings are affected by the underlying hedged forecasted transactions. The estimated fair market value of our outstanding foreign currency forward contracts resulted in a liability of approximately $0.3 million at June 30, 2010. 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 June 30, 2010 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:

	Six Months Ended
	June 30,
	2010			2009
Net unrealized gain (loss) at beginning of period	$	(0.1	)	$	0.2
Activity during period:
Settlement of forward contracts outstanding at beginning of period		0.1			(0.2	)
Net unrealized gain (loss) on outstanding foreign currency forward contracts		(0.3	)		0.4
Net unrealized gain (loss) at end of period	$	(0.3	)	$	0.4

NOTE 7. 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 June 30, 2010 and 2009, our consolidated effective tax rate for continuing operations was 5.1% and 16.5%, respectively. For the six months ended June 30, 2010 and 2009, our consolidated effective tax rate for continuing operations was 11.4% and 16.1%, respectively. The lower tax rate for the 2010 period was principally the result of an increased proportion of income in lower tax jurisdictions and the catch-up effect of our current lower annual projected tax rate.

12

NOTE 8. 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						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Income from continuing operations	$	57.7		$	134.7		$	138.4		$	283.6
Income from continuing operations allocated to non-vested share awards (participating securities)		(0.7	)		(2.2	)		(1.6	)		(4.4	)
Income from continuing operations -basic and diluted	$	57.0		$	132.5		$	136.8		$	279.2
Weighted average shares of common stock outstanding — basic		175.5			173.5			175.5			173.4
Stock options		0.4			0.2			0.4			0.1
Restricted stock awards		0.1			—			0.1			—
Weighted average shares of common stock outstanding — diluted		176.0			173.7			176.0			173.5
Income from continuing operations per share:
Basic	$	0.32		$	0.76		$	0.78		$	1.61
Diluted	$	0.32		$	0.76		$	0.78		$	1.61

For the three months ended June 30, 2010 and 2009, the calculation of weighted average shares of common stock outstanding — diluted excludes 0.9 million and 3.0 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. For the six months ended June 30, 2010 and 2009, the calculation of weighted average shares of common stock outstanding — diluted excludes 0.9 million and 3.8 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 9. STOCK-BASED COMPENSATION

Our stock-based compensation plans provide for the granting or awarding of stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards and cash awards to directors, officers and other key employees. During the three months ended June 30, 2010, we granted 33,551 restricted stock unit awards to employees that vest ratably over three and four years with a weighted average grant-date fair value per share of $30.33. We did not grant any stock option awards, or any restricted stock units with performance and market condition criteria during the three months ended June 30, 2010.

In the quarter ended June 30, 2010, at our annual meeting of stockholders held on May 20, 2010, our employee stock purchase plan was amended to increase the number of shares of common stock reserved for issuance under the plan by 900,000 shares. Our 2007 long-term incentive plan was also amended and restated to add directors as eligible participants and increase the number of shares of common stock reserved for issuance under the plan by 400,000 shares, among other things.

NOTE 10. COMMITMENTS AND CONTINGENCIES

FCPA Investigation

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

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

13

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

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

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

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

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

14

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

Arbitration Matter

In March 2002, Pride Offshore, Inc. (now Seahawk Drilling, Inc.) entered into contracts with BP America Production Co. to design, engineer, manage construction of and commission, as well as operate the drilling package on, the Mad Dog, a platform owned by BP America in the U.S. Gulf of Mexico. In 2004, the drilling package was accepted by BP America, and Pride Offshore’s work under the operation contract commenced. In September 2008, the drilling package was destroyed and the platform was damaged in Hurricane Ike. In September 2009, BP America and an affiliate, on behalf of itself and its joint venture partners, filed an arbitration notice under the contracts, claiming that Pride Offshore breached its express and implied warranties under the construction contract and is liable for fault and gross fault in performing the contracts. At the time, BP America alleged damages in excess of $10 million, with no further specificity. The parties engaged in mediation of the claims in May 2010. Also in May 2010, BP America claimed damages of $282 million for the loss of the drilling package and $19 million for damage to the platform. BP America also alleged loss of production, without specifying an amount. The parties did not resolve the matter through mediation and have resumed the arbitration process.

Under our master separation agreement with Seahawk entered into at the time of the Seahawk spin-off in August 2009, we agreed to assume any obligations arising from the BP America contracts discussed above, which would include potential obligations arising from the construction of the drilling package. Although our insurance underwriters have reserved the right to raise coverage issues, we expect the claims generally to be covered under applicable insurance policies. We believe BP America’s claims will be barred or substantially limited by the limitation of liability and indemnity provisions of the contracts. We intend to continue to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of this matter 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 this matter. We believe that the matter has not adversely affected, and is not likely to adversely affect, our relationship with BP America in any material respect.

Environmental Matters

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

We are currently subject to a pending administrative proceeding initiated in July 2009 by a governmental authority of Spain pursuant to which such governmental authority is seeking payment in an aggregate amount of approximately $4 million for an alleged environmental spill originating from the Pride North America while it was operating offshore Spain. We expect to be indemnified for any payments resulting from this incident by our client under the terms of the drilling contract. The client has posted guarantees with the Spanish government to cover potential penalties. 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.

15

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 June 2009, in response to this letter, the Board 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, and the parties have agreed on a deferral of the matter of up to 120 days to await further developments in the FCPA investigation.

The special committee of the board is continuing to evaluate the issues raised by the demand letter and derivative suits, with the advice of independent counsel.

Loss of Pride Wyoming

In September 2008, the Pride Wyoming, a 250-foot slot-type jackup rig owned by Seahawk and operating in the U.S. Gulf of Mexico, was deemed a total loss for insurance purposes after it was severely damaged and sank as a result of Hurricane Ike. All proceeds related to the insured value of the rig were received in 2008. Costs for removal of the wreckage have been and are expected to continue to be covered by our insurance. Under the master separation agreement between us and Seahawk, Seahawk will be responsible for any removal costs, legal settlements and legal costs associated with the Pride Wyoming not covered by insurance. At Seahawk’s request, we will be required to finance, on a revolving basis, some or all of the costs for removal of the wreckage and salvage operations until receipt of insurance proceeds. In May 2010, Seahawk requested that we pay an invoice in the amount of $6.8 million for a portion of the removal of the wreckage. We have recorded a liability for the $6.8 million and a receivable of the same amount based on a claim that we made under our insurance policies.

Potential Seahawk Tax-Related Guarantees

In 2006, 2007 and 2009, Seahawk received tax assessments from the Mexican government related to the operations of certain of Seahawk’s subsidiaries. Seahawk is responsible for these assessments following the spin-off. Pursuant to local statutory requirements, Seahawk has provided and may provide additional surety bonds or other suitable collateral to contest these assessments. Pursuant to a tax support agreement between us and Seahawk, we have agreed, at Seahawk’s request, to guarantee or indemnify the issuer of any such surety bonds or other collateral issued for Seahawk’s account in respect of such Mexican tax assessments made prior to the spin-off date. The amount of such bonds or other collateral could total up to approximately $151.6 million based on current exchange rates. Beginning on July 31, 2012, on each subsequent anniversary thereafter, and on August 24, 2015, Seahawk will be required to provide substitute credit support for a portion of the collateral guaranteed or indemnified by us, so that our obligations are terminated in their entirety by August 24, 2015. Pursuant to the tax support agreement, Seahawk is required to pay us a fee based on the actual credit support provided. As of June 30, 2010, we had not provided any guarantee or indemnification for any surety bonds or other collateral under the tax support agreement.

16

Former Amethyst Joint Venture Litigation

Prior to March 2001, we had an approximately 30% interest in joint venture companies organized to construct, own and operate four deepwater semisubmersible drilling rigs, later named the Pride Carlos Walter, Pride Brazil, Pride Portland and Pride Rio de Janeiro. In January 2000, the joint venture partner commenced litigation against Petróleo Brasileiro S.A. through various controlled companies, including the four rig-owning joint venture companies, challenging the cancellation of certain drilling contracts related to six rigs, including the four rigs listed above. We acquired our former joint venture partner’s interest in certain of the joint venture companies, including the four rig-owning companies, in separate transactions in March 2001 and November 2006. During this period and at the time of the November 2006 acquisition, we assigned all of our rights and interests in the Petrobras litigation to the joint venture partner, and the joint venture partner agreed (i) to indemnify us for any liability arising from the litigation and (ii) to cause our subsidiaries to be removed from the litigation if, and as soon as, such removal was possible without materially adversely affecting, in the partner’s reasonable opinion, the partner’s profile for recovery of damages under such litigation. Over the course of the litigation, the Brazilian courts have issued rulings in favor of both the joint venture partner and Petrobras. In February 2008, the ruling of the Brazilian Superior Court of Justice, an appellate court, in favor of Petrobras was published, and the parties have since filed various clarification motions, which remain pending and which could alter any final judgment. Once the Brazilian Superior Court of Justice issues a final opinion, the parties to the litigation, including our former joint venture partner, will have the right to seek appeal to the Federal Supreme Court and may have the right to file an additional appeal or motion to a different panel of the Brazilian Superior Court of Justice. If the various motions and appeals are unsuccessful, the plaintiffs, including the rig-owning companies we acquired, could be liable for attorneys’ fees (customarily calculated as a percentage of the amount in controversy) estimated to be approximately 150 million reis, or approximately $85 million (based on current exchange rates), plus an inflationary adjustment since commencement of the litigation and interest. The ruling of the Superior Court suggests that any such liability would be apportioned among the seven plaintiffs, in which case our subsidiaries’ liability would be approximately 60% of the total. As noted above, the former joint venture partner has agreed to indemnify us for any and all of such liability we incur. Any such indemnification claims by us would constitute general unsecured claims. As a result, we cannot give assurance when or to what extent such claims would be paid. No amounts have been accrued related to the matter. Because the litigation is being pursued by the former joint venture partner and not by us, we believe that it has not adversely affected, and is not likely to adversely affect, our relationship with Petrobras in any material respect. We currently have eight rigs contracted to Petrobras, including the four rigs named above.

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 $422.0 million at June 30, 2010. These letters of credit and surety bonds are issued under a number of facilities provided by several banks and other financial institutions.

NOTE 11. SEGMENT AND ENTERPRISE-RELATED 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 two 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.

17

Summarized financial information for our reportable segments are as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Deepwater revenues:
Revenues excluding reimbursables	$	219.0		$	232.4		$	436.9		$	444.5
Reimbursable revenues		3.5			2.4			6.5			8.9
Total Deepwater revenues		222.5			234.8			443.4			453.4
Midwater revenues:
Revenues excluding reimbursables		89.1			113.1			182.8			242.1
Reimbursable revenues		0.2			0.6			0.7			3.4
Total Midwater revenues		89.3			113.7			183.5			245.5
Independent Leg Jackups revenues:
Revenues excluding reimbursables		21.0			69.9			52.4			148.0
Reimbursable revenues		0.6			0.3			0.8			0.5
Total Independent Leg Jackups revenues		21.6			70.2			53.2			148.5
Other		16.7			20.7			32.8			43.8
Corporate		0.2			0.1			0.2			0.2
Total revenues	$	350.3		$	439.5		$	713.1		$	891.4
Earnings (loss) from continuing operations:
Deepwater	$	83.0		$	125.2		$	170.5		$	229.1
Midwater		12.7			36.9			43.6			95.5
Independent Leg Jackups		(12.1	)		30.3			(13.2	)		69.7
Other		1.0			0.4			1.6			2.3
Corporate		(27.3	)		(28.5	)		(59.0	)		(59.9	)
Total	$	57.3		$	164.3		$	143.5		$	336.7
Capital expenditures:
Deepwater	$	99.1		$	231.9		$	589.8		$	424.8
Midwater		27.7			10.2			40.1			15.1
Independent Leg Jackups		4.7			3.6			13.2			7.2
Other		0.5			1.6			0.7			2.0
Corporate		7.0			9.5			11.7			12.9
Discontinued operations		(0.3	)		4.0			(0.1	)		12.7
Total	$	138.7		$	260.8		$	655.4		$	474.7
Depreciation and amortization:
Deepwater	$	21.9		$	19.1		$	42.6		$	37.8
Midwater		12.5			11.2			24.6			22.7
Independent Leg Jackups		8.6			7.0			16.1			14.0
Other		—			0.1			0.1			0.2
Corporate		1.7			1.9			3.4			4.1
Total	$	44.7		$	39.3		$	86.8		$	78.8

18

Segment assets primarily consist of property and equipment. Our total long-lived assets, net, by segment as of June 30, 2010 and December 31, 2009 were as follows:

	June 30,		December 31,
	2010		2009
Total long-lived assets:
Deepwater	$	4,392.2	$	3,836.1
Midwater		712.9		680.5
Independent Leg Jackups		261.6		261.2
Other		19.8		23.1
Corporate		93.2		89.4
Total	$	5,479.7	$	4,890.3

For the three months ended June 30, 2010 and 2009, we derived 98% and 97%, respectively, of our revenues from countries outside of the United States. For the six months ended June 30, 2010 and 2009, we derived 98% and 97%, respectively, of our revenues from countries outside of the United States.

Significant Customers

Revenues, as a percentage of total consolidated revenues, from our customers for the three months and six months ended June 30, 2010 and 2009 that contributed more than 10% of total consolidated revenues were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Petroleos Brasileiro S.A.		38	%		31	%		38	%		28	%
Total S.A.		19	%		13	%		19	%		14	%
BP America and affiliates		14	%		3	%		13	%		3	%
Exxon Mobil Corporation		3	%		10	%		3	%		10	%

NOTE 12. OTHER SUPPLEMENTAL INFORMATION

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

	Six Months Ended
	June 30,
	2010			2009
Decrease (increase) in:
Trade receivables	$	10.7		$	58.7
Other current assets		52.6			15.9
Other assets		10.4			(14.6	)
Increase (decrease) in:
Accounts payable		(12.0	)		(26.5	)
Accrued expenses		(53.0	)		(36.4	)
Other liabilities		(4.7	)		3.7
Net effect of changes in operating accounts	$	4.0		$	0.8
Cash paid during the year for:
Interest	$	44.6		$	23.8
Income taxes		23.5			97.7
Change in capital expenditures in accounts payable		19.2			9.9

19

NOTE 13. SUBSEQUENT EVENTS

We have evaluated subsequent events through the issuance date of the unaudited consolidated financial statements. No subsequent events have taken place that require disclosure in this filing.

20

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 June 30, 2010 and for the three and six months ended June 30, 2010 and 2009 included elsewhere herein, and with our annual report on Form 10-K for the year ended December 31, 2009. 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 Part II of this quarterly report and 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 July 28, 2010, we operated a fleet of 24 rigs, consisting of three deepwater drillships, 12 semisubmersible rigs, seven independent leg jackups and two managed deepwater drilling rigs. We also have three deepwater drillships under construction. Our customers include major integrated oil and natural gas companies, state-owned national oil companies and independent oil and natural gas companies. Our competitors range from large international companies offering a wide range of drilling services to smaller companies focused on more specific geographic or technological areas.

Our primary strategic focus is on ownership and operation of floating offshore rigs, particularly deepwater rigs. Although crude oil prices have declined from the record levels reached in mid-2008 and the current market for deepwater drilling services remains uncertain in the near term, we believe the long-term prospects for deepwater drilling are positive given that the expected growth in oil consumption from developing nations, limited growth in crude oil supplies and high depletion rates of mature oil fields, together with geologic successes, improving access to promising offshore areas and new, more efficient technologies, will continue to be catalysts for the long-term exploration and development of deepwater fields. Since 2005, we have invested or committed to invest over $3.8 billion in the expansion of our deepwater fleet, including four new ultra-deepwater drillships, one of which was delivered in the first quarter of 2010 and three of which are under construction. Three of the drillships have multi-year contracts at favorable rates. Since 2005, we also have disposed of non-core assets, generating $1.6 billion in proceeds, enabling us to increasingly focus our financial and human capital on deepwater drilling. In addition, on August 24, 2009, we completed the spin-off of Seahawk Drilling, Inc., which holds the assets and liabilities that were associated with our mat-supported jackup rig business.

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 activities are less sensitive to general economic factors, serve to provide further stability in the deepwater sector. However, the Deepwater Horizon incident and its consequences, as discussed further below, have increased the near-term uncertainty in the sector. Our contract backlog at June 30, 2010 totals $6.5 billion and is comprised primarily of contracts with large integrated oil and national oil companies for deepwater rigs.

Recent Developments

U.S. Gulf of Mexico and Deep Ocean Ascension

On May 30, 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement of the U.S. Department of the Interior, at the time known as the Minerals Management Service (the “BOEM”), issued a notice to lessees and operators implementing a six-month moratorium on drilling activities with respect to new wells in water depths greater than 500 feet in the U.S. Gulf of Mexico. The notice also stated that the BOEM would not consider, during the six-month moratorium period, drilling permits for wells and related activities for those water depths. In addition, the notice ordered the operators of 33 wells covered by the moratorium that were being drilled to halt drilling and take steps to secure the affected wells. The notice was in response to the April 20, 2010 explosion and fire on the Deepwater Horizon and the resulting oil spill.

21

In addition, effective June 8, 2010, the BOEM issued a separate notice to lessees and operators in the U.S. Gulf of Mexico implementing safety requirements that had previously been recommended in response to the Deepwater Horizon incident. Among other things, this notice requires each operator to conduct a specific review of its operations and to certify to the BOEM that it is in compliance with the new requirements and current regulations. This notice also requires operators to submit independent third-party reports on the design and operation of certain pieces of drilling equipment, including blowout preventers (“BOPs”) and other well control systems. This notice instructs operators to conduct tests on the functionality of various rig parts and to submit the results of those tests to the BOEM. With respect to operations subject to the moratorium, the reports and certifications are required to be provided to the BOEM prior to commencement of operations following expiration of the moratorium.

On June 22, 2010, a federal district court in Louisiana issued a preliminary injunction prohibiting the enforcement of the six-month moratorium. In response to the preliminary injunction, the U.S. Department of the Interior filed a notice of appeal of the preliminary injunction, as well as requests for stay in both the federal district court and the U.S. Court of Appeals for the Fifth Circuit. Each court denied the department’s request for stay of the preliminary injunction during the appeals process.

On July 12, 2010 the BOEM issued another notice to lessees and operators imposing a new moratorium on drilling activities in the U.S. Gulf of Mexico. The notice directs the suspension of drilling operations that use subsea BOPs or surface BOPs on floating facilities. In addition, during the moratorium, the BOEM will not consider approval of pending and future applications for permits to drill wells using subsea BOPs or surface BOPs on floating facilities. The moratorium will apply through November 30, 2010, subject to modification by the BOEM. We cannot currently predict the impact or ultimate duration of the newly issued moratorium or the outcome of the department’s litigation or what, if any, further actions may be taken by the federal government with respect to any moratorium on drilling in the U.S. Gulf of Mexico.

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 is scheduled to commence a five-year contract with BP Exploration & Production Inc. (“BP E&P”) following client testing and acceptance. In addition, the Deep Ocean Clarion is currently undergoing commissioning in South Korea and is expected to be delivered in the third quarter of 2010. Following its mobilization and client acceptance, the Deep Ocean Clarion is expected to commence its five-year contract with BP E&P currently scheduled for the U.S. Gulf of Mexico. We currently have no other rigs operating in the U.S. Gulf of Mexico, but we have been notified by our customer Petrobras that the U.S. Gulf of Mexico is being considered as the initial area of operations for the Deep Ocean Mendocino, our third newbuild drillship. The rig is scheduled for delivery in the first quarter of 2011.

If the moratorium is maintained, BP E&P may be unable to commence drilling operations with the Deep Ocean Ascension in the U.S. Gulf of Mexico according to its original schedule. In such case, and pursuant to the contract, BP E&P may choose either to operate the rig in the U.S. Gulf of Mexico performing operations permitted under the moratorium, to operate the rig outside of the U.S. Gulf of Mexico or to pay the contractual standby dayrate, which approximates the operating dayrate for the drillship. The contract provides for worldwide use of the rig. BP E&P may also choose to exercise the 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. Given the uncertain duration of the U.S. Gulf of Mexico drilling moratorium and the prospects for a more onerous regulatory environment in the region, we and BP E&P are currently in preliminary discussions regarding the possibility of relocating the Deep Ocean Ascension outside the U.S. Gulf of Mexico. We do not believe that the moratorium constitutes a force majeure event under the contract. The drilling contract for the Deep Ocean Clarion has substantially the same provisions.

We are currently working with BP E&P on the acceptance plan, which is expected to commence in August. The testing process primarily involves performance-based testing of rig functionality and crew competency. The contract provides that our right to receive dayrate commences only after BP E&P has accepted the rig. The contract does not currently require the acceptance testing to be completed by a specified date, and BP E&P does not have the right to cancel the contract for the failure to meet acceptance criteria by a specified date. Due to the uncertain duration of the moratorium and changing regulatory environment discussed above, as well as delays due to weather during the hurricane season, it is possible that completion of acceptance testing could extend beyond the third quarter of 2010.

22

BP E&P owns a 65% working interest and is the operator of the exploration well associated with the Deepwater Horizon incident. 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. 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.

The U.S. Gulf of Mexico represents one of three established deepwater drilling basins in the world where an estimated 22.3% of the industry’s deepwater rig capacity is located. The region is a vital contributor to the economy in the United States, providing strong hydrocarbon production growth potential and significant employment opportunities. These attributes support our belief that a permanent drilling moratorium in the U.S. Gulf of Mexico is unlikely. Deepwater drilling is expected to resume once a new regulatory regime is established and companies demonstrate adherence to the regulations and revised operating procedures, as well as a demonstration of effective spill containment technology; however we currently cannot predict the timing for these events.

Despite the economic importance of the region, the deepwater drilling moratorium put into effect by the BOEM on May 27, 2010 and revised on June 15, 2010 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 the uncertainty regarding the amount of time for which the moratorium could be in effect, some contract drillers and operators with floating rigs located in the region may choose to relocate the units to other international drilling areas. At present, only two 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 will relocate to international locations. Should the length of the drilling moratorium be extended or should new regulations, 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, it is expected that additional floating rigs could depart the U.S. Gulf of Mexico, with fewer clients operating in the region. As a result, a more challenging business environment could develop in the international sector, characterized by declining utilization and dayrates.

In addition to the new safety requirements effective June 8, 2010, 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 disrupt or 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 Deepwater Horizon incident and resulting spill, insurance costs across the industry could increase, and certain insurance may be less available or not available at all, which could apply to our fleet.

We expect that any new safety and environmental guidelines or regulations would impose 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 provided in our four 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.

Spin-off of Mat-Supported Jackup Business

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

23

Investments in Deepwater Fleet

In addition to the Deep Ocean Ascension discussed above, we also have agreements for the construction of three additional ultra-deepwater drillships, the Deep Ocean Clarion, Deep Ocean Mendocino and Deep Ocean Molokai. These rigs have scheduled delivery dates in the third quarter of 2010, first quarter of 2011 and fourth quarter of 2011, respectively. Including amounts already paid, commissioning and testing, we expect total costs for these three construction projects to be approximately $2.3 billion, excluding capitalized interest. Through June 30, 2010, we have spent approximately $1.2 billion on these projects. We are scheduled to commence five-year drilling contracts for the Deep Ocean Clarion and Deep Ocean Mendocino following completion of construction, mobilization of the rigs to their initial operating locations and customer testing and acceptance. Although we currently do not have a drilling contract for the Deep Ocean Molokai, we expect that the long-term demand for deepwater drilling capacity in established and emerging basins should provide us with opportunities to contract the rig prior to its delivery date.

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

FCPA Investigation

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

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

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

24

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

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

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

We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our company. For additional information regarding a stockholder demand letter and recently filed derivative cases with respect to these matters, please see the discussion under “—Demand Letter and Derivative Cases” in Note 10 of the Notes to Unaudited Consolidated Financial Statements included in Item 1 of Part I of this quarterly report. In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets. While we have made an accrual in anticipation of a possible resolution with the DOJ and SEC as discussed above, no amounts have been accrued related to any potential fines, sanctions, claims or other penalties referenced in this paragraph, which could be material individually or in the aggregate.

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

25

Our Business

We provide contract drilling services to major integrated, government-owned and independent oil and natural gas companies throughout the world. Our drilling fleet competes on a global basis, as offshore rigs generally are highly mobile and may be moved from one region to another in response to demand. While the cost of moving a rig and the availability of rig-moving vessels may cause the supply and demand balance to vary somewhat between regions, significant variations between regions do not tend to persist long-term because of rig mobility. Key factors in determining which qualified contractor is awarded a contract include pricing, safety performance, operations competency and the relationship with the customer. 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 and political and regulatory environments also affect our customers’ drilling programs. Crude oil and natural gas prices are highly volatile, which has historically led to significant fluctuations in expenditures by our customers for oil and natural gas drilling services. Variations in market conditions during the cycle impact us in different ways depending primarily on the length of drilling contracts in different regions. For example, contracts for jackup rigs in certain shallow water markets are shorter term, so a deterioration or improvement in market conditions tends to quickly impact revenues and cash flows from those operations. Contracts in deepwater and other international offshore markets tend to be longer term, so a change in market conditions tends to have a delayed impact. Accordingly, short-term changes in market conditions may have minimal impact on revenues and cash flows from those operations unless the timing of contract renewals takes place during the short-term changes in the market.

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

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 and which will include our newbuild drillships capable of drilling in ultra-deepwater; 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 rigs, which are included in a non-reported operating segment along with corporate costs and other operations.

26

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 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. Our industry may also experience increased difficulty in attracting and retaining experienced personnel following the Deepwater Horizon incident. 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 have continued to increase in 2010, especially for skilled personnel in certain geographic locations, such as Brazil, Angola and the United States. The more challenging business environment characterized by reduced offshore activity could, however, slow the rate of increase of such costs during the year. An increase in labor costs during 2010 is expected to be most pronounced in the Deepwater segment.

Beginning in 2005, the demand for contract drilling services increased significantly, resulting in increased demand for oilfield equipment and spare parts. This increased demand, when coupled with the consolidation of equipment suppliers, resulted in longer order lead times to obtain critical spare parts and other equipment components essential to our business, along with higher repair and maintenance costs and longer out-of-service time for major repair and upgrade projects. We maintain higher levels of critical spare parts in an effort to minimize unplanned downtime. With the decline in prices for steel and other key inputs that started in 2009 and the slow return in the level of business activity for 2010, we believe that some softening of lead times and pricing for spare parts and equipment is possible during 2010 and for the foreseeable future. The amount and timing of such softening will be affected by our suppliers’ level of backlog and the number of remaining newbuilds, which are expected to increase in 2010, due in large part to the stated incremental demand for deepwater rigs to be built in Brazil to assist in the development of the numerous subsalt discoveries in the Campos and Santos basins.

Crude oil prices have traded in the range of $65 to $87 per barrel for more than a year, and have averaged in excess of $78 per barrel through the first six months of 2010. Crude oil prices were $34 per barrel in February 2009, which followed 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. While the initial months of 2010 were characterized by a similar pattern of caution from many operators toward new exploration and production spending commitments, evidence was present that supported increased spending with a number of new drilling programs commencing in late 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 Deepwater Horizon incident in the U.S. Gulf of Mexico and the subsequent moratorium on deepwater drilling in the region, a new level of uncertainty has once again developed, with operators choosing to delay the commencement of certain projects in the U.S. Gulf of Mexico pending further clarity on a number of industry issues. Worldwide offshore fleet utilization remained flat at approximately 77% at June 30, 2010 compared to 75% at December 31, 2009 and 77% at June 30, 2009. Utilization for the industry’s deepwater fleet has historically been less sensitive to the extreme fluctuations experienced within the shallow water market even during market downturns. However, the timing of the increased spending is expected to remain uncertain until operators have gained more clarity concerning the long-term implications to our industry of the Deepwater Horizon incident, including an understanding of the impact of expected new operating regulations. Also, 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.

27

We believe that long-term market conditions for offshore drilling services are supported by sound fundamental factors but that future demand for our rigs in the worldwide market is uncertain in the short-term due to recent events in the U.S. Gulf of Mexico and its consequences. 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 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. This success has contributed to the demand for our deepwater assets by our clients through the second quarter of 2010, especially those rigs that are capable of operating in water depths of 7,000 feet and greater and possess advanced well construction features leading to 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. During 2009, operators announced a record 25 deepwater discoveries covering an expanding number of offshore basins, such as Ghana, pre-salt Brazil and Sierra Leone, further supporting the long-term sustainability of deepwater drilling demand. An additional 14 deepwater discoveries have been announced since the beginning of 2010, including a discovery offshore Mozambique in East Africa, representing the initial deepwater well drilled offshore in this emerging province. Additional exploration drilling opportunities offshore East Africa are expected to develop in the future with client interest being expressed offshore Tanzania and Kenya. In addition, international oil companies are experiencing greater access to other promising areas offshore, such as India, Malaysia, Australia, Mexico and the Black Sea. We anticipate that the combination of drilling successes, greater access to offshore basins and continued advances in offshore technology, which support increased efficiency in field development efforts like parallel drilling activities, will support the long-term outlook for deepwater rig demand, although the possible increase in the international rig supply resulting in part from the drilling moratorium in the U.S. Gulf of Mexico, as some rigs are relocated to other regions, has created some uncertainty in demand for our deepwater rigs in the short-term.

Our deepwater fleet currently operates in Brazil, West Africa and the Mediterranean Sea. As described above under “Recent Developments,” the Deep Ocean Ascension is currently in the U.S. Gulf of Mexico and will begin commissioning and acceptance testing in August. The Deep Ocean Clarion is expected to be delivered in the third quarter of 2010, with the commencement of a five-year contract with BP E&P currently scheduled for early 2011 in the U.S. Gulf of Mexico following customer testing and acceptance. Including rig days for our three drillships currently under construction, based upon their scheduled delivery dates, we currently have 100% of our available rig days in the last two quarters of 2010 contracted for our deepwater fleet, with 80% in 2011, 67% in 2012 and 55% in 2013. Since an increase in customer demand for deepwater drilling rigs began in 2005, a high percentage of the industry’s fleet of 122 units capable of operating in water depths of 4,500 feet and greater accumulated large contract backlogs and remained under contract through June 30, 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, dayrates for deepwater rigs capable of drilling in greater than 7,000 feet of water and available in 2010 have remained above $400,000 per day. These dayrates have been supported by strong geologic success, especially in Brazil, West Africa, the U.S. Gulf of Mexico, and in some of the new and emerging deepwater regions, which have led to a growing number of commercial discoveries.

Offshore Brazil exploration drilling in the country’s prolific subsalt formation has found numerous crude oil deposits of significant size residing in up to 7,000 feet of water in the Santos Basin. The successful drilling results in Brazil and aggressive exploration 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 subsalt formation and other global interests. The spending plan includes the need for 40 or more incremental deepwater rigs to be deployed in the numerous subsalt fields discovered to date. Petrobras contracted 12 of the 40 rigs in 2008 from the international market and is currently engaged in a process to acquire up to 28 more rigs through construction of some rigs in Brazil, to be ordered by Petrobras. The rigs that Petrobras does not receive from rigs built in Brazil will likely be obtained from the international drilling market. In addition to the successful pre-salt geological trend in the Santos Basin offshore Brazil, a similar subsalt geologic trend has been identified offshore West Africa, which could lead to increased deepwater drilling in that region over the coming years.

28

In addition, deepwater drilling economics have been aided in recent years by an expectation of higher average crude oil prices, supported by global economic expansion and an increased number of deepwater discoveries containing large volumes of hydrocarbons. These improving factors associated with deepwater activity have produced a growing base of development programs requiring multiple years to complete and resulting in long-term contract awards by our customers, especially for projects in the three traditional deepwater basins, and represents a significant portion of our revenue backlog that currently extends into 2016.

Despite the strong long-term outlook for deepwater drilling, we believe that the supply of deepwater rigs currently exceeds client demand. The onset of the global financial crisis in 2008 and the recent events in the U.S. Gulf of Mexico have caused some operators to postpone deepwater exploration and development plans, reducing the urgency to contract deepwater rigs in the near-term. Through the second quarter of 2010, many customers continued to reassess offshore exploration plans and reevaluated a number of planned deepwater development projects in reaction to a period of increased global economic and regulatory uncertainty. In addition, we estimate that the Deepwater Horizon incident with the expected regulatory actions related to drilling in the U.S. Gulf of Mexico could result in the relocation of some of the 33 floating rigs in the region to international regions, which would place dayrates and utilization for rigs in these locations under further pressure.

Industry uncertainty and its impact on our clients’ long-term planning horizons has resulted in clients delaying decisions on deepwater drilling requirements, with some deepwater capacity becoming available during the second half of 2009 and into mid-2010. These delayed contracting decisions, together with limited subleasing of rig time between clients, have contributed to a decline in dayrates for deepwater rigs as more units compete for limited contract opportunities. The lower utilization and dayrate decline are most pronounced among the conventionally moored deepwater semisubmersibles, which generally have the ability to operate in water depths of up to 6,000 feet and employ less sophisticated features. Dayrates for rigs of this technical specification, where six units in the global fleet are currently idle, have weakened considerably from levels experienced up to mid 2008 and could experience further weakness during 2010 as a growing number of rigs complete contracts. Dayrates for the industry’s technologically advanced deepwater rigs have also declined from the mid-2008 peak, including those possessing dynamic positioning technology and more efficient well construction features. Due to operator preference toward the advanced capabilities of these units, it is expected that utilization will remain high over the coming years. Further dayrate declines are possible should clients continue to delay the commencement of offshore programs, especially the large development programs that typically take multiple years to complete. The increase in deepwater drilling capacity, particularly in 2010 and 2011 when as many as 19 uncommitted deepwater rigs are expected to complete construction programs and enter the active global fleet, could place dayrates for these rigs under additional pressure. However, many of these 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.

In light of the possible relocation of additional floating rigs out of the U.S. Gulf of Mexico, new deepwater rig capacity additions and increased availability of existing deepwater rigs as current contracts conclude over the next 12 months, dayrates and utilization for deepwater rigs are expected to have difficulty maintaining current levels until client demand begins to accelerate, and there is an increase in multi-year development projects.

Our Midwater segment consists of six semisubmersible rigs. Four of the rigs currently operate offshore Brazil, with one rig, the Pride South Seas, cold stacked in South Africa and a second rig, the Pride Venezuela, currently mobilizing to Brazil to begin a one year contract in October 2010 following the completion of repairs. We currently have 78% of our available rig days in the last two quarters of 2010 contracted for our midwater fleet, with 76% in 2011, 35% in 2012 and 14% in 2013. Utilization of the industry’s midwater fleet was 88% at June 30, 2010, with 13 rigs idle around the world compared to utilization of 92% at the same time in 2009, when six rigs were idle. Economic instability and uncertainty in crude oil markets during 2009 resulted in a growing number of inactive midwater rigs in the year, and this reduced level of activity carried into 2010, contributing to a more challenging dayrate environment. A modest increase in midwater activity into mid-2010 has been most pronounced in the U.K.

29

and Norwegian sectors of the North Sea as the areas have responded positively to continued price improvement for North Sea Brent crude oil, which averaged $79 per barrel in the second quarter of 2010, compared to $60 per barrel in the second quarter of 2009. Further gains in client demand for midwater rigs during 2010 could be experienced in the Asia Pacific region, where several discoveries have been announced offshore Australia and China. However, a developing weakness in the deepwater rig segment for conventionally moored deepwater rigs could impede further progress in the sector during the year, as these more capable rigs are forced to bid reduced dayrates on work programs in shallower water depths in an attempt to remain active, thereby eliminating a contract opportunity that may have otherwise been available to a midwater unit. Also, the number of midwater rigs located in the U.S. Gulf of Mexico has declined significantly over the past 10 years from approximately 23 rigs in early 2000 to four rigs at June 30, 2010, due primarily to the risk of mooring system failures during hurricane season, marginal geologic prospects and more attractive opportunities in other regions, such as Brazil. We expect the worldwide supply of available midwater rigs to exceed client demand during 2010 with most contract opportunities characterized by short durations of six months or less.

Our Independent Leg Jackup segment, consisting of seven rigs, currently operates in the Middle East and West Africa. We currently have 36% of our available rig days in the last two quarters of 2010 contracted for our independent leg jackup fleet, with 7% contracted in 2011, and no available rig days contracted beyond 2011. Customer demand for jackup rigs declined steadily in 2009 while contract backlogs fell throughout the industry’s existing fleet of rigs and incremental capacity surged. 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, 73 jackup rigs have been added to the global fleet, with another 43 rigs expected to be added by the end of 2012. As of June 30, 2010, 28 of the 43 expected incremental jackup rigs were without contracts. Approximately 23% of the units added to the global jackup rig fleet since 2009 remain idle, having failed to secure an initial contract award following the completion of the construction process. Customer demand for jackup rigs has increased marginally in 2010, especially among the higher specification units with advanced technical features and for some standard units operating in Southeast Asia, the Middle East and West Africa. As of June 30, 2010, 116 jackup rigs were idle in the global fleet, representing segment utilization of 75%, compared to 119 rigs idle at June 30, 2009, or utilization of 73%. Dayrates for standard international-class jackup rigs peaked during 2007 and then fell in 2008 and 2009. With the improvement in utilization, dayrates have begun to stabilize in mid 2010; however, we believe the addition of new capacity, coupled with a growing base of available rigs, will continue to outpace customer demand for rigs, preventing significant improvement in dayrates during 2010 and into 2011. Aggregate jackup rig needs in Mexico declined to 26 rigs at June 30, 2010, from 33 jackups at the same time in 2009. New offshore drilling programs to be launched by Petroleos Mexicanos (“PEMEX”) are expected to require more capable jackup rigs with modern features, potentially limiting the prospects for many standard international-class units.

We experienced approximately 155 and 325 out-of-service days for shipyard maintenance and upgrade projects for the three and six months ended June 30, 2010, respectively, for our existing fleet as compared to approximately 95 and 230 days for the three and six months ended June 30, 2009. For 2010, we expect the total number of out-of-service days to be approximately 570 as compared to 660 days for 2009. The decline in expected out-of-service days in 2010 is primarily due to a reduction of planned shipyard construction projects in our Deepwater segment, partially offset by an increase of planned projects in our Independent Leg Jackup and Midwater segments.

Backlog

Our contracted backlog at June 30, 2010 totaled approximately $6.5 billion, with $2.7 billion attributable to our ultra-deepwater drillship construction projects. We expect approximately $1.5 billion of our total backlog at June 30, 2010 to be realized in the next 12 months. Our backlog at December 31, 2009 was approximately $6.9 billion. We calculate our backlog, or future contracted revenue for our offshore fleet, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation, customer reimbursables and performance bonuses. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the amount disclosed or expected due to various factors. Downtime due to various operating factors, including unscheduled repairs, maintenance, weather and other factors, may result in lower applicable dayrates than the full contractual operating dayrate, as well as the ability of our customers to terminate contracts under certain circumstances.

30

The following table reflects the percentage of rig days committed by year as of June 30, 2010. The percentage of rig days committed is calculated as the ratio of total days committed under firm contracts (as well as scheduled shipyard, survey and mobilization days for 2010) to total available days in the period. Total available days have been calculated based on the expected delivery dates for our three ultra-deepwater rigs under construction.

	For the Years Ending December 31,
	2010(1)			2011			2012			2013
Rig Days Committed
Deepwater		100	%		80	%		67	%		55	%
Midwater		78	%		76	%		35	%		14	%
Independent Leg Jackups		36	%		7	%		0	%		0	%

(1) Represents the six-month period beginning July 1, 2010.

Segment Review

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In millions)						(In millions)
Deepwater revenues:
Revenues excluding reimbursables	$	219.0		$	232.4		$	436.9		$	444.5
Reimbursable revenues		3.5			2.4			6.5			8.9
Total Deepwater revenues		222.5			234.8			443.4			453.4
Midwater revenues:
Revenues excluding reimbursables		89.1			113.1			182.8			242.1
Reimbursable revenues		0.2			0.6			0.7			3.4
Total Midwater revenues		89.3			113.7			183.5			245.5
Independent Leg Jackups revenues:
Revenues excluding reimbursables		21.0			69.9			52.4			148.0
Reimbursable revenues		0.6			0.3			0.8			0.5
Total Independent Leg Jackups revenues		21.6			70.2			53.2			148.5
Other		16.7			20.7			32.8			43.8
Corporate		0.2			0.1			0.2			0.2
Total revenues	$	350.3		$	439.5		$	713.1		$	891.4
Earnings (loss) from continuing operations:
Deepwater	$	83.0		$	125.2		$	170.5		$	229.1
Midwater		12.7			36.9			43.6			95.5
Independent Leg Jackups		(12.1	)		30.3			(13.2	)		69.7
Other		1.0			0.4			1.6			2.3
Corporate		(27.3	)		(28.5	)		(59.0	)		(59.9	)
Total	$	57.3		$	164.3		$	143.5		$	336.7

31

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

	Three Months Ended June 30,										Six Months Ended June 30,
	2010					2009					2010					2009
	Average					Average					Average					Average
	Daily		Utilization			Daily		Utilization			Daily		Utilization			Daily		Utilization
	Revenues (1)		(2)			Revenues (1)		(2)			Revenues (1)		(2)			Revenues (1)		(2)
Deepwater	$	340,800		90	%	$	338,500		95	%	$	337,900		91	%	$	336,800		93	%
Midwater	$	269,700		61	%	$	253,800		82	%	$	267,200		63	%	$	259,700		87	%
Independent Leg Jackups	$	87,000		39	%	$	119,400		92	%	$	99,400		42	%	$	123,100		95	%

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

Deepwater

Revenues for our Deepwater segment decreased $12.3 million, or 5%, for the three months ended June 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to the Pride South Pacific, which, after completion of its upgrade, commenced a new contract mid-January 2010 at a substantially lower dayrate than its second quarter 2009 dayrate, and the Pride Carlos Walter, which completed a water depth upgrade and regulatory inspection in the second quarter of 2010. Together, these two factors contributed to a $21.3 million decrease in revenues in the second quarter of 2010 over the comparable period in 2009. This decrease in revenues was partially offset by higher utilization of the Pride Africa, which experienced approximately 18 out-of-service days as a result of a regulatory inspection in the second quarter of 2009, and of the Pride Brazil, which spent time in the shipyard for contractual upgrades in the second quarter of 2009. These factors contributed to an increase in revenues of $8.4 million over the comparable period in 2009. Average daily revenues increased 1% for the three months ended June 30, 2010 over the comparable period in 2009 as the decreased dayrate for the Pride South Pacific was offset by increased dayrate for the Pride North America. Earnings from operations decreased $42.2 million, or 34%, for the three months ended June 30, 2010 over the comparable period in 2009 due to a decrease in revenue and an increase in repair and maintenance costs for our rigs and start-up costs related to the Deep Ocean Ascension and the Deep Ocean Clarion. Utilization decreased to 90% for the three months ended June 30, 2010 as compared to 95% for the three months ended June 30, 2009 primarily due to the out-of-service time for the Pride Carlos Walter and Pride North America, partially offset by higher utilization for the Pride Africa.

Revenues for our Deepwater segment decreased $10.0 million, or 2%, for the six months ended June 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to the Pride South Pacific, which, after completion of its upgrade, commenced a new contract mid-January 2010 at a substantially lower dayrate than its 2009 dayrate, and the Pride Carlos Walter, which commenced a water depth upgrade and regulatory inspection in the first quarter of 2010 that was completed in the second quarter. Together, these two factors contributed to a $36.2 million decrease in revenues in the first six months of 2010 over the comparable period in 2009. This decrease in revenues was partially offset by higher utilization of the Pride Brazil, which spent time in the shipyard for contractual upgrades in the second quarter of 2009, and the Pride Africa, which experienced approximately 18 out-of-service days as a result of a regulatory inspection in the second quarter of 2009. These factors contributed to an increase in revenues of $23.5 million over the comparable period in 2009. Average daily revenues remained constant for the six months ended June 30, 2010 and the comparable period in 2009 as the decreased dayrate for the Pride South Pacific was offset by increased dayrate for the Pride North America. Earnings from operations decreased $58.6 million, or 26%, for the six months ended June 30, 2010 over the comparable period in 2009 due to a decrease in revenue and an increase in labor costs for the offshore workforce, as well as an increase in repair and maintenance costs for our rigs and start-up costs related to the Deep Ocean Ascension and the Deep Ocean Clarion. Utilization decreased to 91% for the six months ended June 30, 2010 as compared to 93% for the six months ended June 30, 2009 primarily due to the out-of-service time for the Pride Carlos Walter and the Pride Rio de Janeiro, partially offset by higher utilization for the Pride Africa.

32

Midwater

Revenues for our Midwater segment decreased $24.4 million, or 21%, for the three months ended June 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to lower utilization of the Pride South Seas, which was idle during the second quarter of 2010, and the Pride Mexico, which experienced approximately nine out-of-service days in the second quarter of 2010 due to a mechanical failure. These factors contributed to a decrease in revenues of $30.0 million over the comparable period in 2009. This decrease in revenues was partially offset by the Sea Explorer, which operated at a substantially higher dayrate and contributed an incremental $4.9 million of revenues in the second quarter of 2010 over the comparable period in 2009. Earnings from operations decreased $24.2 million, or 66%, for the three months ended June 30, 2010 over the comparable period in 2009 due to decreased revenues, increased labor costs for the Sea Explorer, and increased repair and maintenance costs for the Pride South America, partially offset by lower labor and repair and maintenance costs for the Pride Venezuela and the Pride South Seas. Utilization decreased to 61% for the three months ended June 30, 2010 from 82% for the three months ended June 30, 2009 primarily due to the decreased utilization of the Pride South Seas, Pride South Atlantic and Pride Mexico.

Revenues for our Midwater segment decreased $62.0 million, or 25%, for the six months ended June 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to lower utilization of the Pride South Seas, which was idle during the entire first six months of 2010, and the Pride Venezuela, which was in the shipyard for a rig refurbishment project in the first quarter of 2010 that is expected to be completed in the third quarter of 2010. These factors contributed to a decrease in revenues of $80.2 million over the comparable period in 2009. This decrease in revenues was partially offset by the Sea Explorer, which operated at a substantially higher dayrate in 2010 over the comparable period in 2009, and the increased utilization of the Pride Mexico, which realized an increase in incentive bonus revenue in the first six months of 2010. Together, these rigs contributed an incremental $15.2 million in the first six months of 2010 over the same period in 2009. Earnings from operations decreased $51.9 million, or 54%, for the six months ended June 30, 2010 over the comparable period in 2009 due to decreased revenues and increased labor and repair and maintenance costs for the Pride South America partially offset by lower labor and repair and maintenance costs for the Pride South Seas and the Pride Venezuela. Utilization decreased to 63% for the six months ended June 30, 2010 from 87% for the six months ended June 30, 2009 primarily due to the decreased utilization of the Pride South Seas and Pride Venezuela partially offset by the increased utilization of the Pride Mexico.

Independent Leg Jackup

Revenues for our Independent Leg Jackup segment decreased $48.6 million, or 69%, for the three months ended June 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to the decreased utilization of some of our fleet resulting from a recent decline in the demand for shallow water rigs. The Pride Pennsylvania and the Pride Wisconsin remained stacked throughout the second quarter of 2010, and the Pride Tennessee, which was idle during the first quarter, was also stacked in the second quarter. Additionally, the Pride Cabinda commenced new contracts in March 2010 and June 2010 at dayrates substantially lower than its dayrate in the comparable period in 2009, and the Pride Montana completed a shipyard project in the second quarter of 2010 that resulted in 19 out-of-service days. Average daily revenues decreased 27% for the three months ended June 30, 2010 over the comparable period in 2009 primarily due to the Pride Cabinda, which operated at a significantly lower dayrate in the second quarter of 2010 over the comparable period in 2009. Earnings from operations decreased $42.4 million to a loss of $12.1 million for the three months ended June 30, 2010 compared with earnings of $30.3 million for the comparable period in 2009 due to decreased revenues. Utilization decreased to 39% for the three months ended June 30, 2010 from 92% for the three months ended June 30, 2009, primarily due to the rigs that remained stacked or idle during the second quarter of 2010.

33

Revenues for our Independent Leg Jackup segment decreased $95.3 million, or 64%, for the six months ended June 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to the decreased utilization of some of our fleet resulting from a recent decline in the demand for shallow water rigs. The Pride Pennsylvania and the Pride Wisconsin remained stacked throughout the first six months of 2010, and the Pride Tennessee was idle for the first quarter of 2010 and then stacked in the second quarter. Additionally, the Pride Cabinda experienced approximately 50 out-of-service days in the first quarter of 2010 while awaiting the commencement of a new contract in March 2010, and the Pride Montana commenced a shipyard project in the first quarter of 2010 that was completed in the second quarter and resulted in 44 out-of-service days. Average daily revenues decreased 19% for the six months ended June 30, 2010 over the comparable period in 2009 primarily due to the Pride Cabinda, which operated at a significantly lower dayrate in the first six months of 2010 over the comparable period in 2009. Earnings from operations decreased $82.9 million to a loss of $13.2 million for the six months ended June 30, 2010 compared with earnings of $69.7 million for the comparable period in 2009 due to decreased revenues. Utilization decreased to 42% for the six months ended June 30, 2010 from 95% for the six months ended June 30, 2009, primarily due to the rigs that remained stacked or idle during the first six months of 2010.

Other Operations

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

Revenues decreased $4.0 million, or 19%, for the three months ended June 30, 2010 over the comparable period in 2009 primarily due to the completion of two management contracts in the third and fourth quarters of 2009, partially offset by increased revenue resulting from the commencement of a new management contract in April 2010 at a significantly higher dayrate. Earnings from operations increased $0.6 million, or 150%, for the three months ended June 30, 2010 over the comparable period in 2009 primarily due to the incremental revenue associated with the new management contract, partially offset by the decreased earnings associated with the completion of two management contracts in 2009.

Revenues decreased $11.0 million, or 25%, for the six months ended June 30, 2010 over the comparable period in 2009 primarily due to the completion of two management contracts, in the third and fourth quarters of 2009, partially offset by increased revenue resulting from the commencement of a new management contract in April 2010 at a significantly higher dayrate. Earnings from operations decreased $0.7 million, or 30%, for the six months ended June 30, 2010 over the comparable period in 2009 primarily due to the factors mentioned above.

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.

34

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In millions)						(In millions)
REVENUES
Revenues excluding reimbursable revenues	$	344.0		$	434.4		$	701.4		$	873.7
Reimbursable revenues		6.3			5.1			11.7			17.7
		350.3			439.5			713.1			891.4
COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		217.9			205.2			418.8			405.4
Reimbursable costs		5.1			4.6			9.4			15.8
Depreciation and amortization		44.7			39.3			86.8			78.8
General and administrative		25.5			26.1			55.1			55.2
Gain on sales of assets, net		(0.2	)		—			(0.5	)		(0.5	)
		293.0			275.2			569.6			554.7
EARNINGS FROM OPERATIONS		57.3			164.3			143.5			336.7
OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		—			(0.1	)		—			(0.1	)
Interest income		0.9			0.7			1.1			2.1
Other income (expense), net		2.6			(3.6	)		11.6			(0.6	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		60.8			161.3			156.2			338.1
INCOME TAXES		(3.1	)		(26.6	)		(17.8	)		(54.5	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX	$	57.7		$	134.7		$	138.4		$	283.6

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Revenues Excluding Reimbursable Revenues. Revenues excluding reimbursable revenues for the three months ended June 30, 2010 decreased $90.4 million, or 21%, over the comparable period in 2009. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for the three months ended June 30, 2010 increased $1.2 million, or 24%, over the comparable period in 2009, primarily due to increased reimbursable revenue related to the Pride North America.

Operating Costs. Operating costs for the three months ended June 30, 2010 increased $12.7 million, or 6%, over the comparable period in 2009. The increase is largely attributable to our Deepwater segment, which experienced higher repair and maintenance costs and labor costs as well as increased pre-launch startup costs for the Deep Ocean Ascension and the Deep Ocean Clarion. Partially offsetting these increases were reductions in labor costs in our Midwater, Independent Leg Jackup and Other segments due to lower activity.

Reimbursable Costs. Reimbursable costs for the three months ended June 30, 2010 increased $0.5 million, or 11%, over the comparable period in 2009 primarily due to higher reimbursable costs related to the Pride North America and Pride Africa, partially offset by lower reimbursable costs related to the Pride South Pacific and lower activity across the remainder of the fleet.

Depreciation and Amortization. Depreciation expense for the three months ended June 30, 2010 increased $5.4 million, or 14%, over the comparable period in 2009. This increase relates to capital additions primarily in our Deepwater and Midwater segments.

35

General and Administrative. General and administrative expenses for the three months ended June 30, 2010 decreased $0.6 million, or 2%, over the comparable period in 2009 primarily due to lower labor costs resulting from headcount reductions and lower employee termination costs in addition to lower corporate facility expenses.

Gain on Sale of Assets, Net. We had net gain on sales of assets of $0.2 million for the three months ended June 30, 2010, primarily due to the sale of scrap equipment, and no gains or losses on the sales of assets for the three months ended June 30, 2009.

Interest Expense. We had no interest expense for the three months ended June 30, 2010 and $0.1 million for the three months ended June 30, 2009, due to the capitalization of interest, which totaled $22.9 million and $15.9 million for the three months ended June 30, 2010 and 2009, respectively.

Interest Income. Interest income for the three months ended June 30, 2010 increased $0.2 million, or 29%, over the comparable period in 2009 due to the accrual of interest on balances due from Seahawk partially offset by a decrease in investment income earned as a result of significantly lower investment yields year-over-year and lower average cash balances due to payments made for newbuild drillship construction projects, as compared to the comparable period in 2009.

Other Income (Expense), Net. Other income, net for the three months ended June 30, 2010 increased $6.2 million to $2.6 million for the first three months of 2010 from an expense of $3.6 million for the comparable period in 2009 primarily due to a $6.6 million increase in our foreign exchange gain.

Income Taxes. Our consolidated effective income tax rate for continuing operations for the three months ended June 30, 2010 was 5.1% compared with 16.5% for the three months ended June 30, 2009. The lower tax rate for the 2010 period was principally the result of an increased proportion of income in lower tax jurisdictions and the catch-up effect of our current lower annual projected tax rate.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Revenues Excluding Reimbursable Revenues. Revenues excluding reimbursable revenues for the six months ended June 30, 2010 decreased $172.3 million, or 20%, over the comparable period in 2009. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for the six months ended June 30, 2010 decreased $6.0 million, or 34%, over the comparable period in 2009, primarily due to lower activity in our Midwater and Deepwater segments.

Operating Costs. Operating costs for the six months ended June 30, 2010 increased $13.4 million, or 3%, over the comparable period in 2009. The increase is largely attributable to our Deepwater segment, which experienced higher repair and maintenance costs and labor costs, as well as increased pre-launch startup costs for the Deep Ocean Ascension and the Deep Ocean Clarion. Partially offsetting these increases were reductions in labor costs in our Midwater, Independent Leg Jackup and Other segments due to lower activity.

Reimbursable Costs. Reimbursable costs for the six months ended June 30, 2010 decreased $6.4 million, or 41%, over the comparable period in 2009 primarily due to lower activity across our fleet.

Depreciation and Amortization. Depreciation expense for the six months ended June 30, 2010 increased $8.0 million, or 10%, over the comparable period in 2009. This increase relates to capital additions primarily in our Deepwater and Midwater segments.

General and Administrative. General and administrative expenses for the six months ended June 30, 2010 decreased $0.1 million over the comparable period in 2009 primarily due to lower labor costs resulting from headcount reductions and lower employee termination costs in addition to lower corporate facility expenses.

Gain on Sale of Assets, Net. We had net gain on sales of assets of $0.5 million for the six months ended June 30, 2010 and $0.5 million for the six months ended June 30, 2009, primarily due to the sale of scrap equipment.

36

Interest Expense. We had no interest expense for the six months ended June 30, 2010 and $0.1 million for the six months ended June 30, 2009, due to the capitalization of interest, which totaled $45.9 million and $28.5 million for the six months ended June 30, 2010 and 2009, respectively.

Interest Income. Interest income for the six months ended June 30, 2010 decreased $1.0 million, or 48%, over the comparable period in 2009 due to the decrease in investment income earned as a result of significantly lower investment yields year-over-year, partially offset by the accrual of interest in 2010 on balances due from Seahawk. The decrease was also the result of maintaining lower average cash balances due to payments made for newbuild drillship construction projects, as compared to the comparable period in 2009.

Other Income (Expense), Net. Other income, net for the six months ended June 30, 2010 increased $12.2 million to $11.6 million for the first six months of 2010 from an expense of $0.6 million for the comparable period in 2009 primarily due to a $12.5 million increase in our foreign exchange gain.

Income Taxes. Our consolidated effective income tax rate for continuing operations for the six months ended June 30, 2010 was 11.4% compared with 16.1% for the six months ended June 30, 2009. The lower tax rate for the 2010 period was principally the result of an increased proportion of income in lower tax jurisdictions and the catch-up effect of our current lower annual projected tax rate.

Liquidity and Capital Resources

Our objective in financing our business is to maintain both adequate financial resources and access to additional liquidity. Our $320 million senior unsecured revolving credit facility provides back-up liquidity to meet our on-going working capital needs. Total long-term debt including the current portion at June 30, 2010 was $1.2 billion, and stockholders’ equity was $4.4 billion, resulting in a debt-to-total-capital ratio of 21%. We expect our debt-to-total-capital ratio to peak at approximately 28% later this year. The higher ratio would follow delivery of the second drillship, the Deep Ocean Clarion, and as preparations are made to take delivery of the third drillship the Deep Ocean Mendocino.

During the three months ended June 30, 2010, we used cash on hand and cash flows generated from operations as our primary source of liquidity for funding our working capital needs, debt repayment and capital expenditures. We believe that our cash on hand, cash flows from operations and availability under our revolving credit facility will provide sufficient liquidity through 2010 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, borrowings under our revolving credit facility and proceeds from debt capital market transactions. 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.

37

Sources and Uses of Cash

Cash flows from operating activities

Cash flows from operating activities were $210.4 million for the six months ended June 30, 2010 compared with $374.6 million for the comparable period in 2009. The decrease of $164.2 million was primarily due to a reduction of $174.7 million in cash received for contract drilling services from continuing operations, partially offset by a net change in working capital.

Cash flows used in investing activities

Cash flows used in investing activities were $654.5 million for the six months ended June 30, 2010 compared with $450.4 million for the comparable period in 2009, an increase of $204.1 million. The increase is primarily attributable to an increase in expenditures incurred towards the construction of our ultra-deepwater drillships.

Cash flows from (used in) financing activities

Cash flows used in financing activities were $8.0 million for the six months ended June 30, 2010 compared with cash flows from financing activities of $479.0 million for the comparable period in 2009. The decrease in cash flows from financing activities was primarily due to the issuance in June 2009 of our 8¹/2% Senior Notes due 2019, which resulted in net proceeds of $492.4 million. Cash used for scheduled debt repayments totaled $15.2 million for the six months ended June 30, 2010 and 2009. We also received proceeds of $4.7 million and $1.9 million from employee stock transactions in the six months ended June 30, 2010 and 2009, respectively.

Working Capital

As of June 30, 2010, we had working capital of $189.3 million compared with $661.8 million as of December 31, 2009. The decrease in working capital is primarily due to expenditures of approximately $500 million incurred towards the construction of our four ultra-deepwater drillships.

Revolving Credit Facility

We have a $320 million unsecured revolving credit agreement with a group of banks maturing in December 2011. Borrowings under the credit facility are available to make investments, acquisitions and capital expenditures, to repay and back-up commercial paper and for other general corporate purposes. We may obtain up to $100 million of letters of credit under the facility. The credit facility also has an accordion feature that would, under certain circumstances, allow us to increase the availability under the facility to up to $600 million. Amounts drawn under the credit facility bear interest at variable rates based on LIBOR plus a margin or the alternative base rate. The interest rate margin applicable to LIBOR advances varies based on our credit rating. As of June 30, 2010, there were no outstanding borrowings or letters of credit outstanding under the facility.

We are currently in advanced discussions with certain of the lenders and other banks to amend and restate our credit agreement. The amendment and restatement being discussed would increase the availability under the facility to $720 million and extend the maturity to July 2013. Borrowings under the credit facility would be available to make investments, acquisitions and capital expenditures, to repay and back-up commercial paper and for other general corporate purposes. We would be permitted to obtain up to $100 million of letters of credit under the facility. The credit facility also would include an accordion feature which, under certain circumstances, would allow us to increase availability under the facility to up to $750 million in the aggregate. Amounts drawn under the credit facility would be 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 an alternative base rate.

The amended and restated credit facility being discussed would contain a number of covenants restricting, among other things, liens, indebtedness of our subsidiaries, mergers and dispositions of all or substantially all of our or certain of our subsidiaries’ assets, hedging arrangements outside the ordinary course of business and sale-leaseback transactions. The facility also would require us to maintain certain ratios with respect to EBITDA to interest expenses and debt to tangible capitalization. The facility would contain customary events of default, including with respect to a change of control.

38

The terms of the proposed amendment and restatement of the credit agreement are not final and may be changed. In addition, there can be no assurance that we will enter into an amendment and restatement of our credit facility or increase the availability under the facility.

Other Outstanding Debt

As of June 30, 2010, 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;

• $500.0 million principal amount of 7 3/8% senior notes due 2014; and

• $181.9 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 2010, excluding our commitments related to our drillship construction projects, to be approximately $275 million, of which we have spent approximately $156 million in the first six 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 along with other sustaining capital projects. With respect to our drillship construction projects, we made payments of $427 million in the first six months of 2010, with the total remaining costs estimated to be approximately $1.1 billion. We anticipate making additional payments for the construction of our drillships of approximately $300 million for the remainder of 2010, and approximately $780 million in 2011. 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, borrowings under our revolving credit facility and proceeds from debt capital market transactions.

We anticipate making income tax payments of approximately $40 million to $45 million in 2010, of which $23.5 million has been paid through June 30, 2010.

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

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

Letters of Credit

We are contingently liable as of June 30, 2010 in the aggregate amount of $422.0 million under certain performance, bid and custom bonds and letters of credit. As of June 30, 2010, 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, 2009, 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, 2009. As of June 30, 2010, there were no material changes to this disclosure regarding our contractual obligations made in the annual report.

39

Insurance and Indemnification Matters

Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch throughs, craterings, fires, explosions and pollution. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. Our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well control and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. Our insurance policies typically consist of 12-month policy periods, with the next renewal date for a substantial portion of our insurance program being June 30, 2011.

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

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

Our insurance program also provides coverage for physical damage to, including total loss or constructive total loss of, our rigs, generally excluding damage arising from a named windstorm in the U.S. Gulf of Mexico. This coverage is based on an agreed amount for each rig, and has a $10 million annual aggregate deductible for losses that exceed a separate $10 million per occurrence deductible. For the Deep Ocean Ascension, while the drillship is in the U.S. Gulf of Mexico, we carry $110 million of coverage for physical damage or loss arising from a named windstorm in the U.S. Gulf of Mexico. We currently do not carry U.S. Gulf of Mexico windstorm coverage for physical damage or loss of any other rig.

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

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

40

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

For additional information, please read the risk factor captioned “We are subject to a number of operating hazards, including those specific to marine operations. We may not have insurance to cover all these hazards” in Item 1A of Part II of this quarterly report.

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

Accounting Pronouncements

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

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

In April 2010, the FASB issued ASU 2010-17, Milestone Method of Revenue Recognition, a consensus of the FASB Emerging Issues Task Force. This update provides guidance on defining a milestone and determining when it may be appropriate to apply the milestone method of revenue recognition for research or development transactions. Consideration that is contingent on achievement of a milestone in its entirety may be recognized as revenue in the period in which the milestone is achieved only if the milestone is judged to meet certain criteria to be considered substantive. Milestones should be considered substantive in their entirety and may not be bifurcated. An arrangement may contain both substantive and nonsubstantive milestones that should be evaluated individually. ASU 2010-17 is effective on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after June 15, 2010. We adopted the update as of July 1, 2010. The update will have no effect on our consolidated financial position, results of operations or cash flows as we currently have no research or development transactions.

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

41

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 recent Deepwater Horizon incident in the U.S. Gulf of Mexico 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 indemnification under our drilling contracts;

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

• future operating results and financial condition; and

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

We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. These statements are subject to a number of assumptions, risks and uncertainties, including those described under “— FCPA Investigation” above, in “Risk Factors” in Item 1A of Part II of this quarterly report and Item 1A of our annual report on Form 10-K for the year ended December 31, 2009 and the following:

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

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

• ability to adequately staff our rigs;

• foreign exchange controls and currency fluctuations;

• political stability in the countries in which we operate;

42

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

• cancellation or renegotiation of our drilling contracts or payment or other delays, including acceptance 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, 2009. 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 June 30, 2010 were effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

There were no changes in our internal control over financial reporting that occurred during the second quarter of 2010 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 10 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, 2009.

43

The recent Deepwater Horizon incident in the U.S. Gulf of Mexico and its consequences could have a material adverse effect on our business.

The recent Deepwater Horizon incident in the U.S. Gulf of Mexico and its consequences, including actions taken, or that may be taken, by the U.S. government, other governments or our customers, could have a material adverse effect on our business. Please read “— Recent Developments — U.S. Gulf of Mexico and Deep Ocean Ascension” in Item 2 of Part I of this quarterly report.

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

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

Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property. However, in certain drilling contracts we assume liability for damage to our customer’s property and other third-party property on the rig resulting from our negligence, subject to negotiated caps up to $1 million per occurrence, and in other contracts we are not indemnified by our customers for damage to their property and, accordingly, could be liable for any such damage under applicable law.

In some drilling contracts, we may have liability for third-party damages resulting from pollution or contamination arising from operations under the contract and originating below the surface of the water caused by our gross negligence, or, in some cases, ordinary negligence, subject to negotiated caps up to $10 million per occurrence. In addition, we generally indemnify the customer for legal and financial consequences of spills of industrial waste and other liquids originating from our rigs above the surface of the water. Our contracts with Petrobras in Brazil typically provide that, in the event of any spill of petroleum, oil or other residues into the sea from our rigs, we are responsible for damages up to a capped amount not exceeding $1 million, without regard to our negligence.

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

We maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. Any insurance protection may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. For example, pollution, reservoir damage and environmental risks generally are not fully insurable, as we retain under our liability program any unindemnified liability up to our applicable deductibles and above our coverage limits. In addition, our insurance policy covers only sudden and accidental pollution. Except for a portion of our deepwater fleet, we generally do not maintain business interruption or loss of hire insurance.

The oil and natural gas industry has sustained several catastrophic losses during the past few years, including damage from hurricanes in the Gulf of Mexico. As a result, insurance underwriters have increased insurance premiums and restricted certain insurance coverage such as for losses arising from a named windstorm. For the Deep Ocean Ascension, while the drillship is in the U.S. Gulf of Mexico, we carry $110 million of coverage for physical damage or loss arising from a named windstorm in the U.S. Gulf of Mexico. We currently do not carry U.S. Gulf of Mexico windstorm coverage for physical damage or loss of any other rig.

44

The occurrence of a significant event against which we are not fully insured, or of a number of lesser events against which we are insured but are subject to substantial deductibles, aggregate limits, and/or self-insured amounts, could materially increase our costs and impair our profitability and financial condition. We may not be able to maintain adequate insurance at rates or on terms that we consider reasonable or acceptable or be able to obtain insurance against certain risks. In addition, due to the recent explosion and fire on the Deepwater Horizon and the resulting oil spill in the U.S. Gulf of Mexico, we may have difficulty obtaining some of the insurance coverage we have traditionally maintained, or the premiums for such insurance may be significantly higher.

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

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

					Total
					Number of		Maximum
					Shares		Number of
					Purchased as		Shares That
					Part of a		May Yet Be
	Total Number		Average		Publicly		Purchased
	of Shares		Price Paid		Announced		Under the
Period	Purchased(1)		Per Share		Plan(2)		Plan (2)
April 1-30, 2010		10,067	$	31.01		N/A		N/A
May 1-31, 2010		784	$	25.01		N/A		N/A
June 1-30, 2010		—	$	—		N/A		N/A
Total		10,851	$	30.58		N/A		N/A

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

45

Item 6. Exhibits***

10.1		Pride International, Inc. 2007 Long-Term Incentive Plan (as amended and restated) (incorporated by reference to Appendix A to Pride’s Proxy Statement on Schedule 14A for the 2010 Annual Meeting of Stockholders, File No. 1-13289).
10.2		Second Amendment to Pride International, Inc. Employee Stock Purchase Plan (incorporated by reference to Exhibit 4.10 to Pride’s registration statement on Form S-8, Registration No.333-168503).
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

*	Filed herewith.
†	Management contract or compensatory plan or arrangement.
**	Furnished herewith.
***	Pride and its subsidiaries are parties to several debt instruments that have not been filed with the SEC under which the total amount of securities authorized does not exceed 10% of the total assets of Pride and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii) (A) of Item 601(b) of Regulation S-K, Pride agrees to furnish a copy of such instruments to the SEC upon request.

46

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.

PRIDE INTERNATIONAL, INC.
By:	/s/ BRIAN C. VOEGELE
	Brian C. Voegele
	Senior Vice President and Chief Financial Officer

Date: July 29, 2010

By:	/s/ LEONARD E. TRAVIS
	Leonard E. Travis
	Vice President and Chief Accounting Officer

Date: July 29, 2010

47

INDEX TO EXHIBITS

10.1		Pride International, Inc. 2007 Long-Term Incentive Plan (as amended and restated) (incorporated by reference to Appendix A to Pride’s Proxy Statement on Schedule 14A for the 2010 Annual Meeting of Stockholders, File No. 1-13289).
10.2		Second Amendment to Pride International, Inc. Employee Stock Purchase Plan (incorporated by reference to Exhibit 4.10 to Pride’s registration statement on Form S-8, Registration No.333-168503).
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

*	Filed herewith.
†	Management contract or compensatory plan or arrangement.
**	Furnished herewith.
***	Pride and its subsidiaries are parties to several debt instruments that have not been filed with the SEC under which the total amount of securities authorized does not exceed 10% of the total assets of Pride and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii) (A) of Item 601(b) of Regulation S-K, Pride agrees to furnish a copy of such instruments to the SEC upon request.

48

EX-12

EXHIBIT 12

Computation of Ratio of Earnings to Fixed Charges
(in millions except ratio of earnings to fixed charges)

	Six Months Ended
	June 30,
	2010		2009
Earnings:
Income from continuing operations before income taxes	$	156.2	$	338.1
Portion of rents representative of interest expense		1.9		3.3
Interest on indebtedness, including amortization of deferred loan costs		—		(0.1	)
Amortization of capitalized interest		—		—
Earnings, as adjusted	$	158.1	$	341.3
Fixed Charges:
Portion of rents representative of interest expense	$	1.9	$	3.3
Interest on indebtedness, including amortization of deferred loan costs		—		(0.1	)
Capitalized interest		45.9		28.5
Total fixed charges	$	47.8	$	31.7
Ratio of earnings to fixed charges		3.31x		10.77x

EX-31.1

EXHIBIT 31.1

I, Louis A. Raspino, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pride International, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ Louis A. Raspino
	Louis A. Raspino
	President and Chief Executive Officer (Principal Executive Officer)

Date: July 29, 2010

EX-31.2

EXHIBIT 31.2

I, Brian C. Voegele, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pride International, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ Brian C. Voegele
	Brian C. Voegele
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)

Date: July 29, 2010

EX-32

EXHIBIT 32

Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) (the “Act”) and Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), each of the undersigned, Louis A. Raspino, President and Chief Executive Officer of Pride International, Inc., a Delaware corporation (the “Company”), and Brian C. Voegele, Senior Vice President and Chief Financial Officer of the Company, hereby certifies that, to his knowledge:

(1) the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: July 29, 2010

By:	/s/ Louis A. Raspino
	Louis A. Raspino
	President and Chief Executive Officer (Principal Executive Officer)
By:	/s/ Brian C. Voegele
	Brian C. Voegele
	Senior Vice President and Chief Financial Officer (Principal Financial Officer)

The foregoing certification is being furnished solely pursuant to Section 906 of the Act and Rule 13a-14(b) promulgated under the Exchange Act and is not being filed as part of the Report or as a separate disclosure document.