Pride International 10Q 2009 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________

Form 10-Q

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

For the quarterly period ended June 30, 2009

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 x 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 o 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 x	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 x

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 27, 2009
Common Stock, par value $.01 per share	173,703,741

Table of Contents

	Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements	3
Consolidated Balance Sheets — June 30, 2009 and December 31, 2008	3
Consolidated Statements of Operations — Three months ended June 30, 2009 and 2008	4
Consolidated Statements of Operations — Six months ended June 30, 2009 and 2008	5
Consolidated Statements of Cash Flows — Six months ended June 30, 2009 and 2008	6
Notes to Unaudited Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3. Quantitative and Qualitative Disclosures About Market Risk	39
Item 4. Controls and Procedures	39
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	40
Item 1A. Risk Factors	40
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 4. Submission of Matters to a Vote of Security Holders	42
Item 6. Exhibits	43
Signatures	44

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Pride International, Inc.

Consolidated Balance Sheets

(In millions, except par value)

	June 30,			December 31,
	2009			2008
	(Unaudited)			(As Adjusted)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,115.7		$	712.5
Trade receivables, net		381.2			438.8
Deferred income taxes		23.6			90.5
Prepaid expenses and other current assets		136.2			177.4
Assets held for sale		-			1.4
Total current assets		1,656.7			1,420.6

PROPERTY AND EQUIPMENT		6,559.1			6,067.8
Less: accumulated depreciation		1,583.3			1,474.9
Property and equipment, net		4,975.8			4,592.9
INTANGIBLE AND OTHER ASSETS		73.8			55.5
Total assets	$	6,706.3		$	6,069.0
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	30.3		$	30.3
Accounts payable		120.7			137.3
Accrued expenses and other current liabilities		360.8			403.4
Total current liabilities		511.8			571.0

OTHER LONG-TERM LIABILITIES		129.7			146.2

LONG-TERM DEBT, NET OF CURRENT PORTION		1,176.3			692.9

DEFERRED INCOME TAXES		188.0			258.9

STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 50.0 shares authorized; none issued		-			-
Common stock, $0.01 par value; 400.0 shares authorized; 174.4 and 173.8 shares issued; 173.6 and 173.1 shares outstanding		1.7			1.7
Paid-in capital		2,020.1			2,002.6
Treasury stock, at cost; 0.8 and 0.7 shares		(15.3	)		(13.3	)
Retained earnings		2,691.2			2,408.2
Accumulated other comprehensive income		2.8			0.8
Total stockholders’ equity		4,700.5			4,400.0
Total liabilities and stockholders’ equity	$	6,706.3		$	6,069.0

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

Pride International, Inc.

Consolidated Statements of Operations

(Unaudited)

(In millions, except per share amounts)

	Three Months Ended
	June 30,
	2009			2008
				(As Adjusted)
REVENUES
Revenues excluding reimbursable revenues	$	494.1		$	529.5
Reimbursable revenues		6.6			12.0
		500.7			541.5

COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		262.1			260.5
Reimbursable costs		6.2			11.6
Depreciation and amortization		54.2			52.0
General and administrative, excluding depreciation and amortization		32.8			36.8
Gain on sales of assets, net		(0.5	)		(17.6	)
		354.8			343.3

EARNINGS FROM OPERATIONS		145.9			198.2

OTHER INCOME (EXPENSE), NET
Interest expense		(0.1	)		(6.3	)
Interest income		0.8			5.0
Other income (expense), net		(3.0	)		(0.4	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		143.6			196.5
INCOME TAXES		(21.8	)		(43.4	)

INCOME FROM CONTINUING OPERATIONS, NET OF TAX		121.8			153.1
INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX		2.3			34.3
NET INCOME	$	124.1		$	187.4

BASIC EARNINGS PER SHARE:
Income from continuing operations	$	0.69		$	0.89
Income from discontinued operations		0.01			0.20
Net income	$	0.70		$	1.09
DILUTED EARNINGS PER SHARE:
Income from continuing operations	$	0.69		$	0.87
Income from discontinued operations		0.01			0.19
Net income	$	0.70		$	1.06
SHARES USED IN PER SHARE CALCULATIONS
Basic		173.5			170.2
Diluted		173.6			175.7

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

Pride International, Inc.

Consolidated Statements of Operations

(Unaudited)

(In millions, except per share amounts)

	Six Months Ended
	June 30,
	2009			2008
				(As Adjusted)
REVENUES
Revenues excluding reimbursable revenues	$	1,028.1		$	1,054.2
Reimbursable revenues		21.9			27.4
		1,050.0			1,081.6

COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		532.0			525.1
Reimbursable costs		20.0			26.7
Depreciation and amortization		107.9			102.8
General and administrative, excluding depreciation and amortization		65.9			70.1
Gain on sales of assets, net		(5.4	)		(17.7	)
		720.4			707.0

EARNINGS FROM OPERATIONS		329.6			374.6

OTHER INCOME (EXPENSE), NET
Interest expense		(0.1	)		(17.8	)
Refinancing charges		-			(1.2	)
Interest income		2.1			12.4
Other income (expense), net		0.7			10.0

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		332.3			378.0
INCOME TAXES		(54.0	)		(89.5	)

INCOME FROM CONTINUING OPERATIONS, NET OF TAX		278.3			288.5
INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX		4.7			138.8
NET INCOME	$	283.0		$	427.3

BASIC EARNINGS PER SHARE:
Income from continuing operations	$	1.58		$	1.69
Income from discontinued operations		0.03			0.82
Net income	$	1.61		$	2.51
DILUTED EARNINGS PER SHARE:
Income from continuing operations	$	1.58		$	1.63
Income from discontinued operations		0.03			0.77
Net income	$	1.61		$	2.40
SHARES USED IN PER SHARE CALCULATIONS
Basic		173.4			168.4
Diluted		173.5			177.3

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

Pride International, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

(In millions)

	Six Months Ended
	June 30,
	2009			2008
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:				(As Adjusted)
Net income	$	283.0		$	427.3
Adjustments to reconcile net income to net cash from operating activities:
Gain on sale of Eastern Hemisphere land rigs		(5.4	)		-
Gain on sale of tender-assist rigs		-			(106.7	)
Gain on sale of Latin America and E&P Services segments		-			(32.2	)
Gain on sale of equity method investment		-			(11.4	)
Depreciation and amortization		107.9			107.2
Amortization and write-offs of deferred financing costs		0.9			2.9
Amortization of deferred contract liabilities		(26.9	)		(32.1	)
Gain on sales of assets, net		(5.4	)		(17.7	)
Deferred income taxes		(5.4	)		30.1
Excess tax benefits from stock-based compensation		(0.1	)		(6.4	)
Stock-based compensation		17.9			12.4
Other, net		0.4			1.8
Net effect of changes in operating accounts (See Note 11)		0.8			(92.8	)
Change in deferred gain on asset sales and retirements		4.9			(20.4	)
Increase (decrease) in deferred revenue		(9.1	)		(8.0	)
Decrease (increase) in deferred expense		11.1			5.8
NET CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES		374.6			259.8
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Purchases of property and equipment		(474.7	)		(506.6	)
Proceeds from dispositions of property and equipment		0.8			0.8
Proceeds from the sale of Eastern Hemisphere land rigs, net		9.6			-
Proceeds from sale of tender-assist rigs, net		-			210.8
Proceeds from sale of platform rigs, net		-			64.5
Proceeds from sale of equity method investment		-			15.0
Proceeds from insurance		13.9			-
NET CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES		(450.4	)		(215.5	)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Repayments of borrowings		(15.2	)		(522.0	)
Proceeds from debt borrowings		498.2			68.0
Debt finance costs		(6.0	)		-
Net proceeds from employee stock transactions		1.9			19.2
Excess tax benefits from stock-based compensation		0.1			6.4
NET CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES		479.0			(428.4	)
Increase (decrease) in cash and cash equivalents		403.2			(384.1	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		712.5			890.4
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	1,115.7		$	506.3

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

Pride International, Inc.

Notes to Unaudited Consolidated Financial Statements

NOTE 1. GENERAL

Nature of Operations

Pride International, Inc. (“Pride,” “we,” “our,” or “us”) is a leading international provider of offshore contract drilling services. We provide these services to oil and natural gas exploration and production companies through the operation and management of 44 offshore rigs. We also have four ultra-deepwater drillships under construction.

Basis of Presentation

In the third quarter of 2008, we entered into agreements to sell our Eastern Hemisphere land rig operations and completed the sale of all but one land rig used in those operations in the fourth quarter of 2008. The sale of the remaining land rig closed in the second quarter of 2009. The results of operations, for all periods presented, of the assets disposed of in these transactions have been reclassified to income from discontinued operations. Except where noted, the discussions in the following notes relate to our continuing operations only (see Note 2).

Our unaudited consolidated financial statements included herein have been prepared without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. We believe that the presentation and disclosures herein are adequate to make the information not misleading. In the opinion of management, the unaudited consolidated financial information included herein reflects all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of our financial position, results of operations and cash flows for the interim periods presented. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2008. 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.

Subsequent Events

In preparing these financial statements, we have evaluated subsequent events through July 29, 2009, which is the date the financial statements are being issued.

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.

The recent economic downturn has resulted in stacking additional rigs, and we may be required to stack more rigs or enter into lower dayrate contracts in response to current market conditions. Prolonged periods of low utilization and dayrates could result in the recognition of impairment charges on certain of our rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable. Due to the stacking of additional rigs during the period and recent impairment announcements by other companies in our industry, we performed a projected undiscounted future cash flow analysis as of June 30, 2009 to determine the recoverability of the asset values of our mat-supported jackup fleet and, as a result of this analysis, determined that no impairment was required.

Fair Value Accounting

On January 1, 2008, we adopted, without any impact on our consolidated financial statements, the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurement, for our financial assets and liabilities with respect to which we have recognized or disclosed at fair value on a recurring basis.

In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date for nonfinancial assets and nonfinancial liabilities to fiscal years beginning after November 15, 2008, except for items that are measured at fair value in the financial statements on a recurring basis at least annually. On January 1, 2009, we adopted the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. The adoption did not have a material effect on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be recognized in earnings at each subsequent reporting date. SFAS No. 159 is effective for fiscal years beginning on or after January 1, 2008. The adoption of the provisions of SFAS No. 159 did not have a material impact on our consolidated financial statements.

Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which is an amendment of Accounting Research Bulletin No. 51. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. In addition, SFAS No. 160 requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary. This statement is effective for the fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We adopted SFAS No. 160 on January 1, 2009 but its adoption did not have a material impact on our consolidated financial statements.

On January 1, 2009, we adopted the provisions of SFAS No. 141 (Revised 2007), Business Combinations (SFAS No. 141(R)), which retains the underlying concepts of SFAS No. 141 in that all business combinations are still required to be accounted for at fair value under the acquisition method of accounting, but changes the method of applying the acquisition method in a number of ways. Acquisition costs are no longer considered part of the fair value of an acquisition and will generally be expensed as incurred, noncontrolling interests are valued at fair value at the acquisition date, in-process research and development is recorded at fair value as an indefinite-lived intangible asset at the acquisition date, restructuring costs associated with a business combination are generally expensed subsequent to the acquisition date, and changes in deferred tax asset valuation allowances and income tax uncertainties after the acquisition date generally will affect income tax expense.

In April 2009, the FASB issued FSP SFAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, which amends the guidance in SFAS No. 141(R) to require contingent assets acquired and liabilities assumed in a business combination to be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the measurement period. If fair value cannot be reasonably estimated during the measurement period, the contingent asset or liability would be recognized in accordance with SFAS No. 5, Accounting for Contingencies, and FASB Interpretation (FIN) No. 14, Reasonable Estimation of the Amount of a Loss. Further, this FSP eliminated the specific subsequent accounting guidance for contingent assets and liabilities from Statement 141(R), without significantly revising the guidance in SFAS No. 141. However, contingent consideration arrangements of an acquiree assumed by the acquirer in a business combination would still be initially and subsequently measured at fair value in accordance with SFAS No. 141(R). This FSP is effective for all business acquisitions occurring on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted the provisions of SFAS No. 141(R) and FSP SFAS 141(R)-1 for business combinations with an acquisition date on or after January 1, 2009.

In April 2009, the FASB issued FSP SFAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, which provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP re-emphasizes that regardless of market conditions the fair value measurement is an exit price concept as defined in SFAS No. 157. This FSP clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability and provides additional clarification on estimating fair value when the market activity for an asset or liability has declined significantly. The scope of this FSP does not include assets and liabilities measured under level 1 inputs. FSP SFAS 157-4 is applied prospectively to all fair value measurements where appropriate and will be effective for interim and annual periods ending after June 15, 2009. We adopted the provisions of FSP SFAS 157-4 effective April 1, 2009, with no material impact on our consolidated financial statements.

In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments. This FSP amends SFAS No. 107, Disclosures about Fair Value of Financial Instruments, to require publicly-traded companies, as defined in APB Opinion No. 28, Interim Financial Reporting, to provide disclosures on the fair value of financial instruments in interim financial statements. FSP SFAS 107-1 and APB 28-1 is effective for interim periods ending after June 15, 2009. We adopted the new disclosure requirements in our second quarter 2009 financial statements with no material impact on our consolidated financial statements.

In April 2009, the FASB issued FSP SFAS 115-2 and SFAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments. This FSP amends the other-than-temporary impairment guidance in U.S. GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This FSP does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. FSP SFAS 115-2 and SFAS 124-2 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. An entity may early adopt this FSP only if it also elects to early adopt FSP FAS 157-4. We adopted FSP SFAS 115-2 and SFAS 124-2 effective April 1, 2009, with no material impact on our consolidated financial statements.

In May 2009, the FASB issued SFAS No. 165, Subsequent Events, which establishes (i) the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (ii) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements; and (iii) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. This statement is effective for interim or annual financial periods ending after June 15, 2009, and shall be applied prospectively. We adopted SFAS No. 165 effective April 1, 2009, with no material impact on our consolidated financial statements.

In June 2009, the FASB issued SFAS No. 166, Accounting for Transfers of Financial Assets – An Amendment of FASB Statement No. 140. This statement is a revision to SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and will require more disclosure about transfers of financial assets, including securitization transactions, and where entities have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures. It also enhances information reported to users of financial statements by providing greater transparency about transfers of financial assets and an entity’s continuing involvement in transferred financial assets. This statement will be effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009. Early application is not permitted. We will adopt this statement effective January 1, 2010 and we do not expect the adoption to have a material impact on our consolidated financial statements.

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R). This statement is a revision to FASB Interpretation No. 46 (Revised December 2003), Consolidation of Variable Interest Entities, and changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a reporting entity is required to consolidate another entity is based on, among other things, the other entity’s purpose and design and the reporting entity’s ability to direct the activities of the other entity that most significantly impact the other entity’s economic performance. This statement will require a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. A reporting entity will be required to disclose how its involvement with a variable interest entity affects the reporting entity’s financial statements. This statement will be effective at the start of a reporting entity’s first fiscal year beginning after November 15, 2009. Early application is not permitted. We will adopt this statement effective January 1, 2010 and we do not expect the adoption to have a material impact on our consolidated financial statements.

In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162. The FASB Accounting Standards CodificationTM (Codification) will become the source of authoritative U.S. generally accepted accounting principles (GAAP) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. This statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009.

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 report discontinued operations in accordance with the guidance of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. For the disposition of any asset group accounted for as discontinued operations under SFAS No. 144, we have reclassified the results of operations as discontinued operations for all periods presented. Such reclassifications had no effect on our net income or stockholders’ equity.

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 is subject to certain post-closing adjustments for various indemnities. From the closing date of the sale through June 30, 2009, we recorded a total gain on disposal of $325.4 million, which included certain estimates for the settlement of closing date working capital, valuation adjustments for tax and other indemnities provided to the buyer and selling costs incurred by us. We have indemnified the buyer for certain obligations that may arise or be incurred in the future by the buyer with respect to the business. We believe it is probable that some of these liabilities will be settled with the buyer in cash. Our total estimated gain on disposal of assets includes a $29.7 million liability based on our fair value estimates for the indemnities. In December 2008, the final amount of working capital payable by the buyer to us was determined in accordance with the purchase agreement to be approximately $44.5 million, plus approximately $5.0 million of accrued interest to June 30, 2009. To date, the buyer has not made the required payment, and we have received no assurance that payment will be made. The buyer has made various tax and other indemnification claims totaling approximately $39.6 million, as compared to our recorded liabilities related to these claims of $30.5 million. We continue to pursue collection of the amounts due to us and resolution of the tax and indemnification claims with the buyer. The expected settlement dates for the remaining tax indemnities vary from within one year to several years. Our final gain may be materially affected by the final resolution of these matters.

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

In the third quarter of 2008, we entered into agreements to sell our remaining seven land rigs for $95 million in cash. The sale of all but one rig closed in the fourth quarter of 2008. We leased the remaining rig to the buyer until the sale of that rig closed, which occurred in the second quarter of 2009. We recognized an after-tax gain of $5.2 million on the sale of the rig, which is reflected in our income from discontinued operations for the three and six months ended June 30, 2009.

The following table presents selected information regarding the results of operations of our discontinued operations:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenues	$	2.7		$	43.0		$	22.1		$	91.3
Income before taxes		(2.1	)		3.1			1.1			6.2
Income taxes		0.3			(5.7	)		(0.7	)		(6.3	)
Gain on disposal of assets, net of tax		4.1			36.9			4.3			138.9
Income from discontinued operations	$	2.3		$	34.3		$	4.7		$	138.8

NOTE 3. PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

	June 30,			December 31,
	2009			2008
				(As Adjusted)
Rigs and rig equipment	$	4,952.7		$	4,873.6
Construction-in-progress - newbuild drillships		1,329.1			965.5
Construction-in-progress - other		193.4			165.7
Other		83.9			63.0
Property and equipment, cost		6,559.1			6,067.8
Accumulated depreciation and amortization		(1,583.3	)		(1,474.9	)
Property and equipment, net	$	4,975.8		$	4,592.9

NOTE 4. DEBT

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

Debt consisted of the following:

	June 30,		December 31,
	2009		2008
Senior unsecured revolving credit facility	$	-	$	-
8 1/2% Senior Notes due 2019, net of unamortized discount of $1.8 million		498.2		-
7 3/8% Senior Notes due 2014, net of unamortized discount of $1.6 million and $1.7 million, respectively		498.4		498.3
MARAD notes, net of unamortized fair value discount of $2.1 million and $2.4 million, respectively		210.0		224.9
Total debt		1,206.6		723.2
Less: current portion of long-term debt		30.3		30.3
Long-term debt	$	1,176.3	$	692.9

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 defined in the agreement. The interest rate margin applicable to LIBOR advances varies based on our credit rating. As of June 30, 2009, there were no borrowings or letters of credit outstanding under the facility and availability was $300.0 million.

Effective January 1, 2009, we adopted FSP No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement). FSP APB No. 14-1 applies to any convertible debt instrument that may be wholly or partially settled in cash and requires the separation of the debt and equity components of cash-settleable convertibles at the date of issuance. The FSP is effective for our 3.25% convertible senior notes due 2033, which were originally recorded at face value of $300 million in May 2003 and retired in the second quarter of 2008, and requires retrospective application for all periods presented. We have calculated a theoretical non-cash interest expense based on a similar debt instrument carrying a fixed interest rate but excluding the equity conversion feature and measured at fair value at the time the notes were issued. As a result, the debt component determined for these notes was $251.8 million and the debt discount was $48.2 million. The equity component, recorded as additional paid-in capital, was $31.3 million, which represents the difference between the proceeds from the issuance of the notes and the fair value of the liability, net of deferred taxes of $16.9 million. The fixed interest rate was then applied to the debt component of the notes in the form of an original issuance discount and amortized over the life of the notes as a non-cash interest charge. This resulted in a non-cash increase of our historical interest expense, net of amounts capitalized, of $1.5 million, $9.2 million and $9.9 million for 2008, 2007 and 2006, respectively. Additionally, in accordance with SFAS No. 34, Capitalization of Interest Cost, we capitalized approximately $4.0 million of the incremental interest expense associated with the amortization of the debt discount. Our consolidated income statement for the three and six months ended June 30, 2008 was retroactively modified compared to previously reported amounts as follows (in millions, except per share amounts):

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2008			2008

Additional pre-tax non-cash interest expense	$	0.5		$	1.5
Additional deferred tax benefit		(0.2	)		(0.5	)
Retroactive change in net income and retained earnings	$	0.3		$	1.0

Change to basic earnings per share	$	-		$	-
Change to diluted earnings per share	$	-		$	-

An adjustment to reduce prior period’s retained earnings in the amount of $28.8 million was recorded for the year ended December 31, 2008, reflecting the cumulative impact of the adoption of FSP APB No. 14-1 on our financial statements. The amortization of the debt discount required under FSP APB No. 14-1 is a non-cash expense and has no impact on total operating, investing and financing cash flows in the prior period or future consolidated statements of cash flows.

NOTE 5. DERIVATIVES & FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, foreign currency forward contracts and debt. The estimated fair value of our debt at June 30, 2009 and December 31, 2008 was $1,221.4 million and $702.5 million, respectively, which differs from the carrying amounts of $1,206.6 million and $723.2 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 the carrying amount and estimated fair value of our financial instruments recognized at fair value on a recurring basis:

	June 30, 2009				December 31, 2008
		Estimated Fair Value Measurements
		Quoted Prices	Significant	Significant
		in	Other	Unobservable
	Carrying	Active Markets	Observable Inputs	Inputs	Carrying	Estimated
	Amount	(Level 1)	(Level 2)	(Level 3)	Amount	Fair Value
Derivative Financial Instruments:
Foreign currency forward contracts	$0.4	$ -	$0.4	$ -	$0.2	$0.2

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

Cash Flow Hedging

We have a foreign currency hedging program to moderate the change in value of forecasted payroll transactions and related costs denominated in Euros. We are hedging a portion of these payroll and related costs using forward contracts. When the U.S. dollar strengthens against the Euro, the decline in the value of the forward contracts is offset by lower future payroll costs. Conversely, when the U.S. dollar weakens, the increase in value of forward contracts offsets higher future payroll costs. 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 $7.5 million at June 30, 2009.

All of our foreign currency forward contracts were accounted for as cash flow hedges under SFAS No. 133. The fair market value of these derivative instruments is included in prepaid expenses and other current assets or accrued expenses and other current liabilities, with the cumulative unrealized gain or loss included in accumulated other comprehensive income in our consolidated balance sheet. The estimated fair market value of our outstanding foreign currency forward contracts resulted in an asset of approximately $0.4 million at June 30, 2009. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between derivative contracts and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings and recorded to other income (expense). We did not recognize a gain or loss due to hedge ineffectiveness in our consolidated statements of operations for the six months ended June 30, 2009 related to these derivative instruments.

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

	Six Months Ended
	June 30,
	2009			2008
Net unrealized gain at beginning of period	$	0.2		$	-
Activity during period:
Settlement of forward contracts outstanding at beginning of period		(0.2	)		-
Net unrealized gain on outstanding foreign currency forward contracts		0.4			-
Net unrealized gain at end of period	$	0.4		$	-

NOTE 6. INCOME TAXES

In accordance with generally accepted accounting principles, we estimate the full-year 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, 2009 and June 30, 2008, our consolidated effective tax rate for continuing operations was 15.2% and 22.1%, respectively. For the six months ended June 30, 2009 and June 30, 2008 our consolidated effective tax rate for continuing operations was 16.3% and 23.7%, respectively. The lower tax rate for the 2009 period was principally the result of the tax benefit realized from the finalization of certain tax returns, decreased profitability on some of our midwater rigs operating in high tax rate jurisdictions, and much lower income than in the prior period in our mat-supported jackup segment operating in the United States and Mexico.

In February 2009, we received tax assessments from the Mexican government related to the operations of certain entities for the tax years 2003 and 2004 in the amount of 1,097 million pesos, or approximately $83 million as of June 30, 2009. In order to contest these assessments, Mexican law generally requires taxpayers to post suitable collateral. We expect to vigorously contest these assessments and therefore will be posting bonds or other collateral in the third quarter of 2009. Additional security will be required to be provided to the extent future assessments are contested. We anticipate that the Mexican government will make additional assessments contesting similar deductions for other tax years or entities. As of June 30, 2009, the total amount of tax assessments from the Mexican government was 1,658 million pesos, or approximately $126 million.

NOTE 7. EARNINGS PER SHARE

On January 1, 2009, we adopted the FASB’s FSP Emerging Issues Task Force (EITF) 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. This FSP clarifies that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and should be included in the computation of earnings per share under the “two class” method described in SFAS No. 128, Earnings Per Share. The “two class” method allocates undistributed earnings between common shares and participating securities. We have determined that our grants of unvested restricted stock awards are considered participating securities. We have prepared our current period earnings per share calculations and retrospectively revised our prior period calculations to exclude net income allocated to these unvested restricted stock awards. As a result, basic and diluted income from continuing operations per share decreased by $0.01 for the three months ended June 30, 2008 and $0.02 for the six months ended June 30, 2008.

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,
	2009			2008			2009			2008
Income from continuing operations	$	121.8		$	153.1		$	278.3		$	288.5
Income from continuing operations allocated to non-vested share awards		(2.0	)		(1.6	)		(4.3	)		(3.2	)
Income from continuing operations - basic		119.8			151.5			274.0			285.3
Interest expense on convertible notes		-			1.4			-			5.1
Income tax effect		-			(0.5	)		-			(1.8	)
Income from continuing operations - diluted	$	119.8		$	152.4		$	274.0		$	288.6

Weighted average shares of common stock outstanding - basic		173.5			170.2			173.4			168.4
Convertible notes		-			4.8			-			8.2
Stock options		0.1			0.7			0.1			0.7
Weighted average shares of common stock outstanding – diluted		173.6			175.7			173.5			177.3
Income from continuing operations per share:
Basic	$	0.69		$	0.89		$	1.58		$	1.69
Diluted	$	0.69		$	0.87		$	1.58		$	1.63

The calculation of weighted average shares of common stock outstanding — diluted for the three months ended June 30, 2009 and 2008, excludes 3.0 million and 0.6 million shares of common stock, respectively, issuable pursuant to outstanding stock options and restricted stock awards because their effect was antidilutive. The calculation of weighted average shares of common stock outstanding — diluted for the six months ended June 30, 2009 and 2008 excludes 3.8 million and 1.0 million shares of common stock, respectively, issuable pursuant to outstanding stock options and restricted stock awards because their effect was antidilutive.

NOTE 8. EMPLOYEE STOCK PLANS

Our employee stock-based compensation plans provide for the granting or awarding of stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards and cash awards to directors, officers and other key employees.

During the six months ended June 30, 2009, we granted approximately 1,189,000 stock options at a weighted average exercise price of $17.58. The weighted average fair value per share of these stock-based awards estimated on the date of grant using the Black-Scholes option pricing model was $10.38. The implied volatility used to calculate the Black-Scholes fair value of stock-based awards granted during the six months ended June 30, 2009 increased to 68.7% from 35.1% in 2008, due to the significant changes in the market price of our common stock in 2008. With the exception of volatility, there were no other significant changes in the weighted average assumptions used to calculate the Black-Scholes fair value of stock-based awards granted during the six months ended June 30, 2009 from those used in 2008 as reported in Note 11 of our Annual Report on Form 10-K for the year ended December 31, 2008.

During the six months ended June 30, 2009, we also granted approximately 1,791,000 restricted stock awards with a weighted average grant-date fair value per share of $16.65.

NOTE 9. 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, which is continuing, has found evidence suggesting that payments, which may violate the U.S. Foreign Corrupt Practices Act, were made to government officials in Venezuela and Mexico aggregating less than $1 million. The evidence to date regarding these payments suggests that payments were made beginning in early 2003 through 2005 (a) to vendors with the intent that they would be transferred to government officials for the purpose of extending drilling contracts for two jackup rigs and one semisubmersible rig operating offshore Venezuela; and (b) to one or more government officials, or to vendors with the intent that they would be transferred to government officials, for the purpose of collecting payment for work completed in connection with offshore drilling contracts in Venezuela. In addition, the evidence suggests that other payments were made beginning in 2002 through early 2006 (a) to one or more government officials in Mexico in connection with the clearing of a jackup rig and equipment through customs, the movement of personnel through immigration or the acceptance of a jackup rig under a drilling contract; and (b) with respect to the potentially improper entertainment of government officials in Mexico.

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

The investigation of the matters described above and the Audit Committee's compliance review are ongoing. Accordingly, there can be no assurances that evidence of additional potential FCPA violations may not be uncovered in those or other countries.

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, during the pendency of the investigation to assist us with the investigation and to be available for consultation and to answer questions relating to our business. His retirement benefits will be subject to the determination by our Audit Committee or our Board of Directors that it does not have cause (as defined in his retirement agreement with us) to terminate his employment. Other personnel, including officers, have been terminated or placed on administrative leave or have resigned in connection with the investigation. We have taken and will continue to take disciplinary actions where appropriate and various other corrective action to reinforce our commitment to conducting our business ethically and legally and to instill in our employees our expectation that they uphold the highest levels of honesty, integrity, ethical standards and compliance with the law.

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

We 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 related to these matters, please see the discussion below under "- Demand Letter". In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets. No amounts have been accrued related to any potential fines, sanctions, claims or other penalties referenced in this paragraph, which could be material individually or in the aggregate.

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

Litigation

Since 2004, certain of our subsidiaries have been named, along with numerous other defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi by several hundred individuals that allege that they were employed by some of the named defendants between approximately 1965 and 1986. The complaints allege that certain drilling contractors used products containing asbestos in their operations and seek, among other things, an award of unspecified compensatory and punitive damages. Nine individuals of the many plaintiffs in these suits have been identified as allegedly having worked for us. 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 lawsuits 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 lawsuits.

Environmental Matters

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

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

Demand Letter

In June 2009, we received a demand letter from counsel representing Kyle Arnold. The letter states that Mr. Arnold is one of our stockholders and that he believes that certain of our current and former officers and directors violated their fiduciary duties related to the issues described above under "—FCPA Investigation." The letter requests that our Board of Directors take appropriate action against the individuals in question. In response to this letter, the Board has formed a special committee to evaluate the issues raised by the letter and determine a course of action for the company. The committee has retained counsel to advise it.

Loss of Pride Wyoming

In September 2008, the Pride Wyoming, a 250-foot slot-type jackup rig 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. The rig had a net book value of approximately $14 million and was insured for $45 million. We expect to incur costs of approximately $53 million for removal of the wreckage and salvage operations, not including any costs arising from damage to offshore structures owned by third parties. These costs for removal of the wreckage and salvage operations in excess of a $1 million retention are expected to be covered by our insurance. We will be responsible for payment of the $1 million retention, $2.5 million in premium payments for a removal of wreckage claim and for any costs not covered by our insurance. Initial removal and salvage operations for the Pride Wyoming began in the fourth quarter of 2008 but were suspended due to weather conditions. These operations resumed in May 2009. We have collected a total of $39 million from underwriters through June 2009 for the insured value of the rig and removal of the wreckage, which is net of our deductibles of $20 million and $1 million, respectively.

The owners of four pipelines on which parts of the Pride Wyoming settled have requested that we pay for all costs, expenses and other losses associated with the damage, including loss of revenue. Two owners each have claimed damages in excess of $40 million, one has claimed damages in excess of $21 million, and one has claimed damages in excess of $7 million. Other pieces of the rig may have also caused damage to certain other offshore structures. In October 2008, we filed a complaint in the U.S. Federal District Court pursuant to the Limitation of Liability Act, which has the potential to statutorily limit our exposure for claims arising out of third-party damages caused by the loss of the Pride Wyoming. Based on information available to us at this time, we do not expect the outcome of these potential claims 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 potential claims. Although we believe we have adequate insurance, we will be responsible for any awards not covered by our insurance.

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.

NOTE 10. SEGMENT AND ENTERPRISE-RELATED INFORMATION

Our reportable segments include Deepwater, which consists of our rigs capable of drilling in water depths greater than 4,500 feet, and Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,500 feet or less. Our jackup fleet, which operates in water depths up to 300 feet, is reported as two segments, Independent Leg Jackups and Mat-Supported Jackups, based on rig design as well as our intention to distribute the mat-supported jackup business to our stockholders. We also manage the drilling operations for three deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations. The accounting policies for our segments are the same as those described in Note 1 of our Consolidated Financial Statements.

Summarized financial information for our reportable segments are as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009				2008
Deepwater revenues:
Revenues excluding reimbursables	$	232.4		$	206.6		$	444.5			$	398.4
Reimbursable revenues		2.4			1.6			8.9				4.1
Total Deepwater revenues		234.8			208.2			453.4				402.5

Midwater revenues:										��
Revenues excluding reimbursables		113.1			80.0			242.1				157.7
Reimbursable revenues		0.6			0.8			3.4				2.0
Total Midwater revenues		113.7			80.8			245.5				159.7

Independent Leg Jackup revenues:
Revenues excluding reimbursables		69.9			59.4			148.0				118.1
Reimbursable revenues		0.3			-			0.5				0.1
Total Independent Leg Jackup revenues		70.2			59.4			148.5				118.2

Mat-Supported Jackup revenues:
Revenues excluding reimbursables		55.0			142.3			142.7				289.8
Reimbursable revenues		1.5			2.3			4.1				3.9
Total Mat-Supported Jackup revenues		56.5			144.6			146.8				293.7

Other		25.4			48.4			55.6				106.9
Corporate		0.1			0.1			0.2				0.6
Total revenues	$	500.7		$	541.5		$	1,050.0			$	1,081.6

Earnings (loss) from continuing operations:
Deepwater	$	126.0		$	106.1		$	231.5			$	198.6
Midwater		37.5			20.1			97.2				47.9
Independent Leg Jackups		30.6			27.2			70.5				53.7
Mat-Supported Jackups		(14.7	)		58.6			(7.9	)			113.6
Other		1.8			22.7			9.0				31.3
Corporate		(35.3	)		(36.5	)		(70.7	)			(70.5	)
Total	$	145.9		$	198.2		$	329.6			$	374.6

Capital expenditures:
Deepwater	$	231.9		$	130.9		$	424.8			$	350.0
Midwater		10.2			27.9			15.1				103.7
Independent Leg Jackups		3.6			8.8			7.2				17.7
Mat-Supported Jackups		4.0			4.5			12.9				14.5
Other		1.6			-			2.0				2.0
Corporate		9.5			14.9			12.9				17.8
Discontinued operations		-			0.7			(0.2	)			0.9
Total	$	260.8		$	187.7		$	474.7			$	506.6

Depreciation and amortization:
Deepwater	$	19.1		$	18.4		$	37.8			$	35.7
Midwater		11.2			10.9			22.7				19.8
Independent Leg Jackups		7.0			6.5			14.0				13.1
Mat-Supported Jackups		14.9			14.3			29.1				29.0
Other		0.1			1.1			0.2				3.2
Corporate		1.9			0.8			4.1				2.0
Total	$	54.2		$	52.0		$	107.9			$	102.8

We measure segment assets as property, equipment and goodwill. At June 30, 2009 and December 31, 2008, goodwill of $1.2 million was included in our Mat-Supported Jackup segment. Our total long-lived assets by segment as of June 30, 2009 and December 31, 2008 were as follows:

	June 30,		December 31,
	2009		2008
Total long-lived assets:
Deepwater	$	3,400.5	$	3,014.5
Midwater		676.6		681.8
Independent Leg Jackups		270.6		276.0
Mat-Supported Jackups		514.4		528.8
Other		23.1		10.9
Corporate		91.7		81.8
Discontinued operations		0.1		0.3
Total	$	4,977.0	$	4,594.1

For the three-month periods ended June 30, 2009 and 2008, we derived 94% and 85%, respectively, of our revenues from countries other than the United States. For the six-month periods ended June 30, 2009 and 2008, we derived 92% and 85%, respectively, of our revenues from countries other than the United States.

Significant Customers

Our significant customers were as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2009	2008	2009	2008
Petroleos Brasileiro S.A.	27%	16%	24%	15%
Petroleos Mexicanos S.A.	12%	23%	14%	24%
Total S.A.	12%	7%	12%	8%
BP America and affiliates	2%	11%	2%	11%

NOTE 11. OTHER SUPPLEMENTAL INFORMATION

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

	Six Months Ended
	June 30,
	2009			2008
Decrease (increase) in:
Trade receivables	$	57.6		$	(64.7	)
Prepaid expenses and other current assets		17.0			(0.9	)
Other assets		(14.6	)		(5.2	)
Increase (decrease) in:
Accounts payable		(26.5	)		(14.6	)
Accrued expenses		(36.4	)		(26.0	)
Other liabilities		3.7			18.6
Net effect of changes in operating accounts	$	0.8		$	(92.8	)

Cash paid during the year for:
Interest	$	23.8		$	31.9
Income taxes		97.7			83.3
Change in capital expenditures in accounts payable		9.9			20.2

NOTE 12. SUBSEQUENT EVENTS

Increase in Availability under Revolving Credit Facility

In July 2009, borrowing availability under our unsecured revolving credit facility was increased from $300 million to $320 million.

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, 2009 and for the three months and six months ended June 30, 2009 and 2008 included elsewhere herein, and with our annual report on Form 10-K for the year ended December 31, 2008. 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 29, 2009, we operated a fleet of 44 rigs, consisting of two deepwater drillships, 12 semisubmersible rigs, 27 jackups and three managed deepwater drilling rigs. We also have four deepwater drillships under construction. Our customers include major integrated oil and natural gas companies, state-owned national oil companies and independent oil and natural gas companies. Our competitors range from large international companies offering a wide range of drilling services to smaller companies focused on more specific geographic or technological areas.

We are continuing to increase our emphasis on deepwater drilling. Although crude oil prices have declined from the record levels reached in mid-2008, we believe the long-term prospects for deepwater drilling are positive given that the expected growth in oil consumption from developing nations, limited growth in crude oil supplies and high depletion rates of mature oil fields, together with geologic successes, improving access to promising offshore areas and new, more efficient technologies, will continue to be catalysts for the long-term exploration and development of deepwater fields. Since 2005, we have invested or committed to invest over $3.6 billion in the expansion of our deepwater fleet, including four new ultra-deepwater drillships under construction. Three of the drillships have multi-year contracts at favorable rates, with two scheduled to work in the strategically important deepwater U.S. Gulf of Mexico, which, in addition to our operations in Brazil and West Africa, provides us with exposure to all three of the world’s most active deepwater basins. Since 2005, we also have disposed of non-core assets, generating $1.6 billion in proceeds, to enable us to reinvest our financial and human capital to deepwater drilling. Our transition to a pure offshore focused company with an increasing emphasis on deepwater drilling is complete.

Our customers have reduced exploration and development spending in 2009, especially in midwater and shallow water drilling programs, due to the current economic downturn and decline in crude oil prices. However, we anticipate that deepwater activity will outperform other drilling sectors due to the long-term field development activities of our customers, more favorable drilling economics and the tendency of our customers to plan deepwater drilling programs with a long-term bias and with less concern for short-term fluctuations in crude oil prices. Our contract backlog at June 30, 2009 totals $7.4 billion and is comprised primarily of contracts for deepwater rigs with large integrated oil and national oil companies possessing long-term development plans. Our backlog, together with our existing cash on hand and borrowing availability under our revolving credit facility, is expected to provide sufficient financial resources to sustain our focus through this economic downturn.

Recent Developments

Issuance of 8 ½% Senior Notes due 2019

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

Contract Termination

In March 2009, we accelerated a planned inspection on our midwater semisubmersible Pride Venezuela, commencing the project in March rather than April. The rig had been working offshore Angola. An inspection of a section of the rig’s hull revealed an unacceptable level of corrosion, which will require a dry-dock facility to conduct permanent repairs. No dry-dock facilities exist in Africa that can accommodate a semisubmersible rig the size of the Pride Venezuela. Accordingly, the rig is expected to be relocated outside of Africa for further evaluation and to conduct the necessary repairs. The hull repairs, along with other maintenance and repairs to the rig, were expected to require most of the remaining term of the rig’s then-existing contract, which had been expected to conclude in March 2010. Consequently, in May 2009 we and the customer mutually agreed to the termination of the remaining term of the contract. The contract represented approximately $130 million of our backlog as of March 31, 2009.

Upgrade by S&P to Investment Grade

In March 2009, Standard & Poor’s Ratings Services upgraded our corporate credit rating and the rating on our 7 3/8% senior notes due 2014 to an investment grade BBB-, with a stable outlook. The upgrade reflected our balance sheet improvement over the last several years and leverage metrics that compare similarly to investment grade rated offshore drilling peers.

Investments in Deepwater Fleet

In January 2008, we entered into an agreement to construct a third advanced-capability ultra-deepwater drillship, to be named Deep Ocean Mendocino. The agreement provides for an aggregate fixed purchase price of approximately $635 million. The agreement provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us on or before March 31, 2011. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages for delays during certain periods. We have entered into a multi-year drilling contract with respect to the drillship, which is expected to commence during the second quarter of 2011 following the completion of shipyard construction, mobilization of the rig and customer acceptance testing. Under the drilling contract, the customer may elect, by January 31, 2010, a firm contract term of at least five years and up to seven years in duration. Through June 30, 2009, we have spent approximately $275 million on this construction project. We expect the total project cost, including commissioning and testing, to be approximately $725 million, excluding capitalized interest.

In January 2008, we entered into a five-year contract with respect to the drillship, to be named Deep Ocean Ascension, under construction that we acquired from Lexton Shipping Ltd. for drilling operations in the U.S. Gulf of Mexico. Scheduled delivery of this rig is in the first quarter of 2010. Work on the client’s behalf is expected to commence mid-2010 following the completion of shipyard construction, mobilization of the rig to the U.S. Gulf of Mexico and customer acceptance testing. In connection with the contract, the drillship is being modified from the original design to provide enhanced capabilities designed to allow our clients to conduct subsea construction activities and other simultaneous activities, while drilling or completing the well. Including these modifications, amounts already paid, commissioning and testing, we expect the total project cost to be approximately $750 million, excluding capitalized interest. Through June 30, 2009, we have spent approximately $418 million on this construction project.

In April 2008, we entered into a five-year contract with respect to our drillship, to be named Deep Ocean Clarion, under construction with a scheduled delivery in the third quarter of 2010. The drilling contract is expected to commence during the fourth quarter of 2010 following the completion of shipyard construction, mobilization of the rig to an initial operating location and customer acceptance testing. In connection with the contract, the drillship is being modified from the original design to provide enhanced capabilities designed to allow our clients to conduct subsea construction activities and other simultaneous activities, while drilling or completing the well. Including these modifications, amounts already paid, commissioning and testing, we expect the total project cost to be approximately $715 million, excluding capitalized interest. Through June 30, 2009, we have spent approximately $321 million on this construction project. Also, while we have previously purchased a license to equip the rig for dual-activity use, the rig will not initially be functional as a dual-activity rig, but can be modified to add this functionality in the future.

In August 2008, we entered into an agreement for the construction of a fourth ultra-deepwater drillship, to be named Deep Ocean Molokai. The agreement provides for an aggregate fixed purchase price of approximately $655 million. The agreement provides that, following shipyard construction, commissioning and testing, the drillship is to be delivered to us in or before the fourth quarter of 2011. We have the right to rescind the contract for delays exceeding certain periods and the right to liquidated damages for delays during certain periods. Through June 30, 2009, we have spent approximately $215 million on this construction project. We expect the total project cost, including commissioning and testing, to be approximately $750 million, excluding capitalized interest. Although we currently do not have a drilling contract for this drillship, we expect that the anticipated long-term demand for deepwater drilling capacity in established and emerging basins should provide us with a number of opportunities to contract the rig prior to its delivery date.

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

Spin-off of Mat-Supported Jackup Business

We have filed a Form 10 registration statement with the SEC with respect to the distribution to our stockholders of all of the shares of a subsidiary to be named Seahawk Drilling, Inc. that would hold, directly or indirectly, the assets and liabilities associated with our 20-rig mat-supported jackup business. We believe that the spin-off has the potential to facilitate our growth strategies and reduce our cost of capital, and to allow us to refine our focus and further enhance our reputation as a provider of deepwater drilling services. The spin-off, which we expect to complete in the third quarter of 2009, is contingent upon approval of the final plan by our board of directors, the effectiveness of the Form 10 registration statement and other conditions. There can be no assurance that we will complete the spin-off within that time period or at all. Following the spin-off, we will be

focused on deepwater opportunities with a concentration of high-specification, deepwater rigs, and Seahawk will be focused on shallow water drilling in the Gulf of Mexico. In connection with the spin-off, we expect to cancel certain intercompany balances and contribute approximately $43 million in cash to Seahawk to provide the company with a specified level of working capital. We will conduct, as of the date of the spin-off, a fair value assessment of the long-lived assets of Seahawk to determine whether an impairment loss should be recognized. We will recognize an impairment loss if the carrying value of such assets exceeds their fair value as determined in the assessment. This impairment loss would ultimately result in a reduction to our total dividend to shareholders and a corresponding impairment expense, which would be reclassified to discontinued operations.

Dispositions

In May 2008, we sold our entire fleet of platform rigs and related land, buildings and equipment for $66 million in cash. In connection with the sale, we entered into lease agreements with the buyer to operate two platform rigs until their existing contracts are completed. In March 2009, the contract for one of these rigs was canceled and the rig was subsequently transitioned to the buyer at the beginning of April 2009. A contract extension was granted for the remaining rig, and we will continue to operate that rig until this current contract is completed, which is expected to occur in the third quarter of 2009. The leases require us to pay to the buyer all revenues from the operation of the rigs, less operating costs and a small per day management fee, which we retain.

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

We have reclassified the historical results of operations of our former Latin America Land and E&P Services segments, which we sold for $1.0 billion in 2007, our three tender-assist rigs and our Eastern Hemisphere land rig operations to discontinued operations.

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

Loss of Pride Wyoming

FCPA Investigation

We are engaged in discussions with the DOJ and the SEC regarding a potential negotiated resolution of these matters, which could be settled during 2009 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. No amounts have been accrued related to any potential fines, sanctions, claims or other penalties, which could be material individually or in the aggregate, but an accrual could be made as early as the third quarter of 2009. 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. There can be no assurance that these discussions 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 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 related to these matters, please see the discussion under "- Demand Letter" in Note 9 of the Notes to Unaudited Financial Statements 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. 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.

Our Business

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

The markets for our drilling services have historically been highly cyclical. Our operating results are significantly affected by the level of energy industry spending for the exploration and development of crude oil and natural gas reserves. Oil and natural gas companies’ exploration and development drilling programs drive the demand for drilling services. These drilling programs are affected by a number of factors, including oil and natural gas companies’ expectations regarding crude oil and natural gas prices. Some drilling programs are influenced by short-term expectations, such as shallow water drilling programs in the U.S. Gulf of Mexico and the Middle East, while others, especially deepwater drilling programs, are typically subject to a longer term view of crude oil prices. Other drivers include anticipated production levels, worldwide demand for crude oil and natural gas products and many other factors. The availability of 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 the shallow water U.S. Gulf of Mexico 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. Mobilization fees are deferred and recognized as revenue over the term of the contract.

We organize our reportable segments based on the general asset class of our drilling rigs. Our reportable segments include Deepwater, which currently consists of our eight rigs capable of drilling in water depths greater than 4,500 feet, and Midwater, which currently consists of our six semisubmersible rigs capable of drilling in water depths of 4,500 feet or less. Our jackup fleet, which operates in water depths up to 300 feet, is reported as two segments, Independent Leg Jackups, currently consisting of seven rigs, and Mat-Supported Jackups, currently consisting of 20 rigs. We also manage the drilling operations for three deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations.

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

Our industry has traditionally been affected by shortages of, and competition for, skilled rig crew personnel during high levels of activity in the drilling industry, and due to the aging workforce and the training and skill set of applicants. Even as overall industry activity declines, we expect these personnel shortages to continue, especially in the deepwater segments, due to the number of newbuild deepwater rigs expected to be delivered through 2012 and the need for highly skilled personnel to operate these rigs. To better retain and attract skilled rig personnel, we offer competitive compensation programs and have increased our focus on training and management development programs. We believe that labor costs may continue to increase in 2009 for skilled personnel in certain geographic locations although the more challenging business environment characterized by reduced offshore activity may slow the rate of increase of such costs in 2009. Prior to this reduction in offshore activity, increased demand for contract drilling operations resulted in an increased demand for oilfield equipment and spare parts, which, when coupled with the consolidation of equipment suppliers, resulted in longer order lead times to obtain critical spares and other critical equipment components essential to our business, higher repair and maintenance costs and longer out-of-service time for major repair and upgrade projects. We anticipate maintaining higher levels of critical spares to minimize unplanned downtime. With the decline in prices for steel and other key inputs and the decline in level of business activity, we believe that some softening of lead times and pricing for spare parts and equipment is likely to occur. The amount and timing of such softening will be affected by our suppliers’ level of backlog and the number of remaining newbuilds.

The decline in crude oil prices that began in late 2008, following the onset of the global financial crisis, deteriorating global economic fundamentals and the resulting decline in crude oil demand in a number of the world’s largest oil consuming nations, continues to have a negative impact in 2009 on customer demand for offshore rigs. Crude oil prices have averaged approximately $52 per barrel during the first six months of 2009 compared to $111 per barrel over the same six months in 2008. These lower prices have contributed heavily to a reduction in planned 2009 offshore drilling expenditures by our customers. Worldwide offshore fleet utilization has declined to its lowest level since early 2000, to approximately 78% at June 30, 2009. This decline has been more pronounced in exploration activities, which are characterized by shorter term projects. Deepwater drilling activity continues to display more resilience in 2009 relative to other offshore drilling activities, especially for projects currently in a development phase. This is due to the long-term planning horizon common among our customers when engaged in deepwater development programs. Utilization for the industry’s deepwater fleet has historically not been subject to the extreme fluctuations as experienced within the shallow water market even during market downturns. Although crude oil prices have trended higher in the second quarter of 2009, averaging approximately $60 per barrel compared to $43 per barrel in the first quarter of 2009, some clients continue to engage in subletting of rigs in an effort to reduce their capital commitments during a period of increased uncertainty. An increase in the subleasing of deepwater rig capacity could become more pronounced during the second half of 2009, especially if crude oil prices begin to trend lower, and could result in declining dayrates for deepwater rigs.

We believe that long-term market conditions for offshore drilling services are supported by sound fundamental factors and that demand for certain offshore rigs, especially deepwater units, should continue to remain strong for the next several years, producing attractive opportunities for our deepwater rigs, including those units under construction. We expect the long-term global demand for deepwater offshore contract drilling services to be driven by the return of expanding worldwide demand for crude oil and natural gas as global economic growth returns, an increased focus by oil and natural gas companies on deepwater offshore prospects, and increased global participation by national oil companies. Customer requirements for deepwater drilling capacity remain steady in the current business environment, as successful results in exploration drilling conducted over the past several years have led to numerous prolonged field development programs around the world, placing deepwater assets in limited supply through 2010. We believe that long-term economic factors and demand for crude oil will lead to a higher trading range for crude oil prices in the future. With geological successes in exploratory markets, such as the numerous discoveries to date in the pre-salt formation offshore Brazil and, in general, more favorable conditions allowing international oil companies access to promising offshore basins, together with continued advances in offshore technology which support increased efficiency in field development efforts, we believe exploration and production companies will continue to pursue the exploration and development of new deepwater fields. In addition, we believe that the need for deepwater rigs will continue to grow for existing offshore development projects.

Our deepwater fleet currently operates in West Africa, Brazil and the Mediterranean Sea, and we expect to expand into the strategically important U.S. Gulf of Mexico region in 2010 with the delivery of two of our four deepwater drillships currently under construction. Including rig days for our drillships under construction, based upon their scheduled delivery dates, we have 91% of our available rig days for our deepwater fleet contracted in the last two quarters of 2009, 89% in 2010, 81% in 2011 and 67% in 2012. Customer demand for deepwater drilling rigs has increased steadily since 2005, with the industry’s fleet of 104 units experiencing near full utilization through the second quarter of 2009. The high customer demand led to a steep rise in deepwater rig dayrates, exceeding $600,000 per day for some multi-year contracts agreed to during 2008. Dayrates for deepwater rigs remain strong, especially for those rigs capable of drilling in greater than 7,000 feet of water, as evidenced by several contract awards during the year at dayrates greater than $500,000 per day. The deepwater drilling business continues to be supported by strong geologic success, especially in Brazil, West Africa and the U.S. Gulf of Mexico, and the emergence of new, promising deepwater regions, such as India, Malaysia, North Africa, Mexico and the Black Sea, along with advances in seismic gathering and interpretation and well completion technologies. These developments have contributed to record backlog levels and contracted rig utilization at or near 100% through the end of 2009. In addition, deepwater drilling economics have been aided in recent years by an expectation of higher average crude oil prices 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 Brazil, West Africa and the U.S. Gulf of Mexico, and represents a significant portion of our revenue backlog that currently extends into 2016. However, since the onset of the global financial crisis in 2008, urgency by clients to contract deepwater rigs, which was evident well into 2008, has diminished through the first six months of 2009. Many customers are reassessing offshore exploration plans and re-evaluating a number of deepwater development projects in reaction to a period of increased global economic uncertainty. Some deepwater capacity has become available during the second quarter of 2009 as a result of operators’ reluctance to contract rigs in the near-term and an increased sensitivity to the cost of rig services in an uncertain oil price environment, leading to a decline in dayrates. The dayrate decline is most pronounced among the conventionally moored deepwater semisubmersibles, but could become increasingly evident among those rigs capable of operating in greater than 7,000 feet of water should crude oil prices trend lower during the second half of 2009, subleasing activity among customers expand and incremental deepwater capacity scheduled for delivery from the shipyard in 2011 remain without a contract. We remain engaged in discussions with a number of our clients regarding future deepwater rig needs, especially in 2011 and 2012.

Our midwater fleet currently operates offshore Africa and Brazil, and we expect this geographic presence to remain unchanged through 2009. We currently have 68% of our available rig days for our midwater fleet contracted in the last two quarters of 2009, 67% in 2010, 63% in 2011 and 35% in 2012. During 2009, customer needs for midwater rigs have declined, resulting in some rigs being idle. Subleasing of rigs by clients has increased due to the uncertain economic climate, increased difficulty with accessing capital resources and desire by many clients to reduce capital expenditures to a level which approximates projected cash flows in the year. We expect the subletting of rig time in 2009 to remain active among customers until confidence in a favorable outlook for crude oil prices increases. Midwater rig availability is currently increasing, with eight rigs available or stacked worldwide at June 30, 2009, compared to four rigs during the same period in 2008, leading to a more challenging near- to intermediate-term dayrate environment. Many of the industry’s midwater rigs are utilized in mature offshore regions that are sensitive to crude oil price volatility, such as the U.K. North Sea. In addition, the number of midwater rigs located in the U.S. Gulf of Mexico has declined significantly from 19 rigs in 2006 to five rigs at present, due primarily to the risk of mooring system failures during hurricane season, marginal geologic prospects and more attractive opportunities in other regions, such as Brazil. Contract opportunities for midwater rigs with availability over the next 12 months currently remain limited, increasing the risk of additional idle capacity and leading to deteriorating utilization and dayrates.

Our independent leg jackup rig fleet currently operates in Mexico, the Middle East, Asia Pacific and West Africa. We currently have 69% of our available rig days for our independent leg jackup fleet contracted in the last two quarters of 2009, 25% in 2010, 7% in 2011 and none in 2012. Since 2007, 56 jackup rigs have been added to the global fleet, with another 61 expected to be added in 2009 to 2011. Customer demand in 2009 has fallen below the supply of international jackup rigs, creating an increased level of idle rig capacity while contract durations have shortened throughout the existing fleet of jackup rigs. The majority of rigs being delivered in 2009 and beyond are without contracts. At present, 11 of the 56 delivered new build jackups have failed to obtain an initial contract award following the completion of construction and are idle in various shipyards in the Far East. Dayrates for standard international-class jackup rigs peaked during 2008 and have continued to fall in 2009 as the utilization rate has declined below 83%. We expect jackup utilization and dayrates to continue to decline in the near to intermediate term as customers in the Middle East, West Africa and Asia reassess drilling programs and new capacity is absorbed into the fleet. The aggregate jackup rig needs in Mexico remain promising in 2009, with five incremental jackups added since the beginning of the year and another five to ten jackup rigs expected to be added by early 2010 as PEMEX attempts to reverse substantial crude oil production declines. During 2008, PEMEX indicated a shifting focus toward geologic prospects in deeper water and, therefore, an increased emphasis on rigs with a water depth rating of 250 feet or greater.

Our mat-supported jackup fleet operates in the United States and Mexico. We currently have 9% of our mat-supported jackup rig days contracted for the second half of 2009, with no contracted days in 2010. The shallow water U.S. Gulf of Mexico is a mature offshore basin where drilling activity is typically conducted by small, independent exploration and production companies that are heavily influenced by the price of natural gas. Production prospects are typically small (5-20 billion cubic feet) in size and jackup rigs are employed by clients for short-term, well-to-well programs. Throughout most of 2008, utilization and dayrates for the U.S. Gulf of Mexico based jackup rigs improved steadily due to higher natural gas prices and a reduction in the supply as rigs migrated to international markets. With the historically high crude oil price in mid-2008, a number of

clients employed jackup rigs to drill small accumulations of crude oil, further constraining the supply of rigs in the region. However, since the fourth quarter of 2008, the fleet utilization for U.S. jackup rigs has declined steadily and is below 30 percent at June 30, 2009. With fewer than 20 rigs under contract, this low utilization has led to a decline in dayrates. Customers have significantly curtailed offshore drilling programs in 2009 principally due to lower natural gas and crude oil prices, their inability to access capital to fund exploration and production spending and the reallocation of resources to more attractive drilling opportunities. Jackup rig activity and dayrates are expected to persist at depressed levels through 2009 and possibly into 2010. Although, industry-wide, 16 U.S. mat-supported jackup rigs have been stacked in 2009 and another four permanently removed from service due to the potential for a prolonged weak business environment, rig dayrates remain depressed and could decline to levels approaching the cash cost to operate rigs. In Mexico, offshore rigs are contracted solely by Petróleos Mexicanos (“PEMEX”), the national oil company of Mexico. PEMEX is focused on new field exploration and development prospects that increasingly require the use of rigs with water depth capability of greater than 200 feet. We expect that jackup demand in Mexico will continue to be strong for rigs with water depth capabilities of 250 feet and greater. From the beginning of 2008 through June 2009, we relocated five of our eleven mat-supported jackup rigs located in Mexico back to the U.S. where four of these units are cold stacked and one remains idle. Of our six remaining mat-supported jackup rigs in Mexico, four are operating under PEMEX contracts that expire between August and October 2009 and two are idle as of June 30, 2009. The two idle units, the Pride Nebraska and Pride Arkansas, were relocated to the U.S. Gulf of Mexico in July 2009 and cold stacked until activity levels improve. PEMEX is currently reviewing its jackup needs to determine if there is additional work for the four mat-supported jackups with contracts expiring in 2009.

We experienced approximately 95 and 230 out-of-service days for shipyard maintenance and upgrade projects for the three and six months ended June 30, 2009, respectively, for our existing fleet as compared to approximately 210 and 525 days for the three and six months ended June 30, 2008, respectively. For 2009, we expect the total number of out-of-service days to be approximately 925 as compared to 655 days for 2008. Expected out-of-service days for 2009 include 290 days for the Pride Venezuela.

Backlog

Our backlog at June 30, 2009, totaled approximately $7.4 billion for our executed contracts, with $2.6 billion attributable to our ultra-deepwater drillships under construction. We expect approximately $1.2 billion of our total backlog to be realized in the next 12 months. Our backlog at December 31, 2008 was approximately $8.6 billion. We calculate our backlog, or future contracted revenue for our offshore fleet, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation, customer reimbursables and performance bonuses. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the amount disclosed or expected due to various factors. Downtime due to various operating factors, including unscheduled repairs, maintenance, weather and other factors, may result in lower applicable dayrates than the full contractual operating dayrate, as well as the ability of our customers to terminate contracts under certain circumstances.

The following table reflects the percentage of rig days committed by year as of June 30, 2009. The percentage of rig days committed is calculated as the ratio of total days committed under firm contracts (as well as scheduled shipyard, survey and mobilization days for 2009 and 2010) to total available days in the period. Total available days have been calculated based on the expected delivery dates for our four ultra-deepwater rigs under construction.

	For the Years Ending December 31,
	2009(1)	2010	2011	2012
Rig Days Committed
Deepwater	91%	89%	81%	67%
Midwater	68%	67%	63%	35%
Independent Leg Jackups	69%	25%	7%	0%
Mat-Supported Jackups	9%	0%	0%	0%

____________

(1)	Represents the six-month period beginning July 1, 2009.

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,
	2009			2008			2009			2008
Deepwater revenues:	(In millions)						(In millions)
Revenues excluding reimbursables	$	232.4		$	206.6		$	444.5		$	398.4
Reimbursable revenues		2.4			1.6			8.9			4.1
Total Deepwater revenues		234.8			208.2			453.4			402.5

Midwater revenues:
Revenues excluding reimbursables		113.1			80.0			242.1			157.7
Reimbursable revenues		0.6			0.8			3.4			2.0
Total Midwater revenues		113.7			80.8			245.5			159.7

Independent Leg Jackup revenues:
Revenues excluding reimbursables		69.9			59.4			148.0			118.1
Reimbursable revenues		0.3			-			0.5			0.1
Total Independent Leg Jackup revenues		70.2			59.4			148.5			118.2

Mat-Supported Jackup revenues:
Revenues excluding reimbursables		55.0			142.3			142.7			289.8
Reimbursable revenues		1.5			2.3			4.1			3.9
Total Mat-Supported Jackup revenues		56.5			144.6			146.8			293.7

Other		25.4			48.4			55.6			106.9
Corporate		0.1			0.1			0.2			0.6
Total revenues	$	500.7		$	541.5		$	1,050.0		$	1,081.6

Earnings (loss) from continuing operations:
Deepwater	$	126.0		$	106.1		$	231.5		$	198.6
Midwater		37.5			20.1			97.2			47.9
Independent Leg Jackups		30.6			27.2			70.5			53.7
Mat-Supported Jackups		(14.7	)		58.6			(7.9	)		113.6
Other		1.8			22.7			9.0			31.3
Corporate		(35.3	)		(36.5	)		(70.7	)		(70.5	)
Total	$	145.9		$	198.2		$	329.6		$	374.6

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2009				2008				2009				2008
	Average Daily Revenues (1)		Utilization (2)		Average Daily Revenues (1)		Utilization (2)		Average Daily Revenues (1)		Utilization (2)		Average Daily Revenues (1)		Utilization (2)


Deepwater	$	338,500		95%	$	298,300		96%	$	336,800		93%	$	287,200		96%
Midwater	$	253,800		82%	$	217,800		68%	$	259,700		87%	$	220,800		66%
Independent Leg Jackups	$	119,400		92%	$	112,000		83%	$	123,100		95%	$	113,800		82%
Mat-Supported Jackups	$	89,000		35%	$	87,700		86%	$	95,400		42%	$	90,500		85%

____________

(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 increased $26.6 million, or 13%, for the three months ended June 30, 2009 over the comparable period in 2008 primarily due to higher contracted dayrates for the Pride Angola, the Pride Brazil and the Pride Carlos Walter. Collectively, these three rigs contributed approximately $43 million of incremental revenues over the comparable period in 2008. This increase in revenues was partially offset by the decreased revenue from the Pride Rio de Janeiro, which worked on a short-term assignment at a higher dayrate in the second quarter of 2008, and decreased 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. Primarily as a result of these factors, average daily revenues increased 13% for the three months ended June 30, 2009 over the comparable period in 2008. Earnings from operations increased $19.9 million, or 19%, for the three months ended June 30, 2009 over the comparable period in 2008 due to the increase in revenues, partially offset by an increase in repair and maintenance costs across our fleet as well as higher costs for our rig crews. Utilization decreased to 95% for the three months ended June 30, 2009 as compared to 96% for the three months ended June 30, 2008 primarily due to the decreased utilization of the Pride Africa.

Revenues for our deepwater segment increased $50.9 million, or 13%, for the six months ended June 30, 2009 over the comparable period in 2008. The increase in revenues is primarily due to higher contracted dayrates for the Pride Angola, the Pride Brazil and the Pride Carlos Walter, which collectively contributed approximately $68 million of incremental revenues over the comparable period in 2008. This increase in revenues was partially offset by the decreased revenue from the Pride Rio de Janeiro, which worked at a higher average dayrate in 2008 as a result of a short-term assignment, and the decreased utilization of the Pride Africa and the Pride North America, which experienced a decrease in the number of days worked of 22 and 10 days, respectively. Primarily as a result of these factors, average daily revenues increased 17% for the six months ended June 30, 2009 over the comparable period in 2008. Earnings from operations increased $32.9 million, or 17%, for the six months ended June 30, 2009 over the comparable period in 2008 due to the increase in revenues, partially offset by an increase in total labor costs for our rig crews as well as an increase in repair and maintenance costs for our rigs. Utilization decreased to 93% for the six months ended June 30, 2009 as compared to 96% for the three months ended March 31, 2008 primarily due to the decreased utilization of the Pride Africa and the Pride North America.

Midwater

Revenues for our midwater segment increased $32.9 million, or 41%, for the three months ended June 30, 2009 over the comparable period in 2008. The Pride Mexico, which commenced a five-year contract in Brazil beginning in July 2008, contributed an incremental $22.9 million of revenues in the second quarter of 2009 as a result of earning no revenues in the comparable period in 2008 as it was in the shipyard. The increase in revenues was also due to the increased utilization of the Sea Explorer and the Pride South Atlantic, which worked 57 more days during the 2009 period as a result of less shipyard time. In addition, dayrates for the Sea Explorer increased at the beginning of 2009 pursuant to the terms of its current contract. The increase in revenues during the second quarter of 2009 was partially offset by the Pride Venezuela, which earned no dayrate during the quarter as a result of unplanned repairs and the subsequent agreement with the customer to terminate its current contract. Average daily revenues increased 17% for the three months ended June 30, 2009 over the comparable period in 2008. Earnings from operations increased $17.4 million, or 87%, for the three months ended June 30, 2009 over the comparable period in 2008 due to the increase in revenues partially offset by increased costs for our rig crews. Utilization increased to 82% for the three months ended June 30, 2009 from 68% for the three months ended June 30, 2008 primarily due to the increased utilization of the Pride Mexico, the Pride South Seas and the Sea Explorer.

Revenues for our midwater segment increased $85.8 million, or 54%, for the six months ended June 30, 2009 over the comparable period in 2008. The Pride Mexico contributed an incremental $40.4 million of revenues for the six months ended June 30, 2009 as a result of less shipyard time than in the comparable period in 2008. The increased revenues were also due to the increased utilization of the Sea Explorer and the Pride South Seas, which worked 109 more days during the 2009 period as a result of less shipyard time. In addition, dayrates for the Sea Explorer increased at the beginning of 2009 pursuant to the terms of its current contract. The increase in revenues was partially offset by lower revenues for the Pride Venezuela. Average daily revenues increased 18% for the six months ended June 30, 2009 over the comparable period in 2008. Earnings from operations increased $49.3 million, or 103%, for the six months ended June 30, 2009 over the comparable period in 2008 due to the increase in revenues offset partially by increased costs for our rig crews. Utilization increased to 87% for the six months ended June 30, 2009 from 66% for the six months ended June 30, 2008 primarily due to the increased utilization of the Pride Mexico, the Pride South Seas and the Sea Explorer.

Independent Leg Jackups

Revenues for our independent leg jackup segment increased $10.8 million, or 18%, for the three months ended June 30, 2009 over the comparable period in 2008 primarily due to the increased utilization of the Pride Cabinda, which was in the shipyard for the entire second quarter of 2008, and the Pride Montana, which was operating on a contract with higher dayrates in the 2009 period. Together, these two rigs contributed an incremental $21.4 million of revenue for the three months ended June 30, 2009 over the comparable period in 2008. The increase in revenues was partially offset by the decreased utilization of the Pride Tennessee, which underwent a regulatory inspection in the second quarter of 2009. Average daily revenues increased 7% for the three months ended June 30, 2009 over the comparable period in 2008 primarily due to higher utilization and dayrates for the Pride Cabinda and the Pride Montana. Earnings from operations increased $3.4 million, or 13%, for the three months ended June 30, 2009 over the comparable period in 2008 due to increased revenues offset partially by increased costs for our rig crews. Utilization increased to 92% for the three months ended June 30, 2009 from 83% for the three months ended June 30, 2008 primarily due to reduced shipyard time for the Pride Cabinda and Pride North Dakota.

Revenues for our independent leg jackup segment increased $30.3 million, or 26%, for the six months ended June 30, 2009 over the comparable period in 2008 primarily due to the increased utilization of the Pride Cabinda, as a result of less shipyard time in the 2009 period as compared to the 2008 period, and the Pride Montana, which was operating on a contract with higher dayrates in the 2009 period. Together, these two rigs contributed an incremental $42.7 million of revenue for the six months ended June 30, 2009 over the comparable period in 2008. The increase in revenues was partially offset by the decreased utilization of the Pride Tennessee. Average daily revenues increased 8% for the six months ended June 30, 2009 over the comparable period in 2008 primarily due to higher utilization and dayrates for the Pride Cabinda and the Pride Montana. Earnings from operations increased $16.8 million, or 31%, for the six months ended June 30, 2009 over the comparable period in 2008 due to increased revenues offset partially by increased costs for our rigs crews. Utilization increased to 95% for the six months ended June 30, 2009 from 82% for the six months ended June 30, 2008, primarily due to reduced shipyard time for the Pride Cabinda and Pride North Dakota.

Mat-Supported Jackups

Revenues for our mat-supported jackup segment decreased $88.1 million, or 61%, for the three months ended June 30, 2009 over the comparable period in 2008 due to decreased activity driven largely by the lower level of industrial activity in the U.S., declines in commodity prices, particularly natural gas, and a reduction in capital available to our customers. The one percent increase in average daily revenues for the three months ended June 30, 2009 over the comparable period in 2008 was more than offset by lower utilization across the fleet. Earnings from operations decreased $73.3 million, or 125%, for the three months ended June 30, 2009 over the comparable period in 2008 primarily due to lower revenues. Utilization decreased to 35% for the three months ended June 30, 2009 from 86% for the comparable period in 2008. The decrease in utilization is primarily due to five rigs that worked all or part of the 2008 period, but were stacked the entire 2009 period, the stacking of three additional rigs during 2009 as the demand for drilling services has declined, as well as the loss of the Pride Wyoming during Hurricane Ike in September 2008.

Revenues for our mat-supported jackup segment decreased $146.9 million, or 50%, for the six months ended June 30, 2009 over the comparable period in 2008. Average daily revenues increased 5% for the six months ended June 30, 2009 over the comparable period in 2008. Earnings from operations decreased $121.5 million, or 107%, for the six months ended June 30, 2009 over the comparable period in 2008 primarily due to lower revenues. Utilization decreased to 42% for the six months ended June 30, 2009 from 85% for the comparable period in 2008. The decrease in utilization is primarily due to five rigs that worked all or part of the 2008 period, but were stacked the entire 2009 period, the stacking of three additional rigs during 2009, as well as the loss of the Pride Wyoming.

Other Operations

Other operations include our three deepwater drilling operations management contracts that expire in 2009, 2011 and 2012 (with early termination permitted in certain cases) and two deepwater drilling operations management contracts that ended in the third and fourth quarters of 2008, respectively, our 10 platform rigs that were sold in May 2008 and other operating activities.

Revenues decreased $23.0 million, or 48%, for the three months ended June 30, 2009 over the comparable period in 2008 primarily due to the sale of our platform rig fleet in May 2008 and the termination of two management contracts in the second half of 2008. The decline was also attributable to incremental reimbursable revenue we received in 2008 in connection with a labor contract. Earnings from operations decreased $20.9 million, or 92%, for the three months ended June 30, 2009 over the comparable period in 2008 primarily due to the decline in revenues and the sale of our platform fleet in May 2008.

Revenues decreased $51.3 million, or 48%, for the six months ended June 30, 2009 over the comparable period in 2008 primarily due to the sale of our platform rig fleet in May 2008. The decline was also attributable to the termination of two management contracts in the second half of 2008 and a reduction in reimbursable revenue period-over-period in connection with a labor contract. Earnings from operations decreased $22.3 million, or 71%, for the six months ended June 30, 2009 over the comparable period in 2008 primarily due to these revenue decreases and the sale of our platform fleet in May 2008.

Results of Operations

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(In millions)						(In millions)
REVENUES
Revenues excluding reimbursable revenues	$	494.1		$	529.5		$	1,028.1		$	1,054.2
Reimbursable revenues		6.6			12.0			21.9			27.4
		500.7			541.5			1,050.0			1,081.6

COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		262.1			260.5			532.0			525.1
Reimbursable costs		6.2			11.6			20.0			26.7
Depreciation and amortization		54.2			52.0			107.9			102.8
General and administrative, excluding depreciation and amortization		32.8			36.8			65.9			70.1
Gain on sales of assets, net		(0.5	)		(17.6	)		(5.4	)		(17.7	)
		354.8			343.3			720.4			707.0

EARNINGS FROM OPERATIONS		145.9			198.2			329.6			374.6

OTHER INCOME (EXPENSE), NET
Interest expense		(0.1	)		(6.3	)		(0.1	)		(17.8	)
Refinancing charges		-			-			-			(1.2	)
Interest income		0.8			5.0			2.1			12.4
Other income (expense), net		(3.0	)		(0.4	)		0.7			10.0
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		143.6			196.5			332.3			378.0
INCOME TAXES		(21.8	)		(43.4	)		(54.0	)		(89.5	)
INCOME FROM CONTINUING OPERATIONS, NET OF TAX	$	121.8		$	153.1		$	278.3		$	288.5

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008

Revenues Excluding Reimbursable Revenues. Revenues excluding reimbursable revenues for the three months ended June 30, 2009 decreased $35.4 million, or 7%, over the comparable period in 2008. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for the three months ended June 30, 2009 decreased $5.4 million, or 45%, over the comparable period in 2008 primarily due to lower activity in our other segment.

Operating Costs. Operating costs for the three months ended June 30, 2009 increased $1.6 million, or 1%, over the comparable period in 2008. The increases were attributable to our deepwater, midwater and independent leg jackup segments. Operating costs for the Pride Venezuela were $8.5 million higher in the 2009 period as a result of unplanned repairs in 2009. Operating costs for the Pride Cabinda and the Pride Mexico were $4.5 million and $6.1 million higher, respectively. Both of these rigs worked for the entire period in 2009, while they had extended shipyard time in the 2008 period. In addition, rig labor costs were $6.1 million higher for these segments (excluding the rig labor costs associated with the Pride Cabinda and the Pride Mexico) in the 2009 period as compared to the 2008 period. Partially offsetting the increases, operating costs in our mat-supported jackup segment were $14.9 million lower as a result of the lower level of operating activity in the 2009 period. In addition, operating costs in our other segment decreased by $13.3 million due to the sale of our platform rigs in 2008 and the termination of two management contracts in the second half of 2008. Operating costs as a percentage of revenues, excluding reimbursables, were 53% and 49% for the three months ended June 30, 2009 and 2008, respectively.

Reimbursable Costs. Reimbursable costs for the three months ended June 30, 2009 decreased $5.4 million, or 47%, over the comparable period in 2008 primarily due to lower activity in our other segment.

Depreciation and Amortization. Depreciation expense for the three months ended June 30, 2009 increased $2.2 million, or 4%, over the comparable period in 2008. This increase relates to capital additions primarily in our midwater and deepwater segments.

General and Administrative. General and administrative expenses for the three months ended June 30, 2009 decreased $4.0 million, or 11%, over the comparable period in 2008. The decrease was due to a $4.1 million reduction related to costs incurred in the 2008 period for our ERP implementation and other related projects, a $4.1 million decrease in wages and related benefits, including special termination and retirement benefits paid in 2008, and a reduction of $1.1 million in expenses related to the ongoing investigation described under “—FCPA Investigation” above, partially offset by an increase of $3.8 million in costs related to the separation of our mat-supported jackup business and an increase of $0.5 million due to higher corporate facility rental expenses.

Gain on Sale of Assets, Net. We had net gain on sales of assets of $0.5 million for the three months ended June 30, 2009 primarily due to the recognition of the deferred gain on sale from the sale of our platform fleet in May 2008. We had net gain on sales of assets of $17.6 million for the three months ended June 30, 2008 primarily from such sale.

Interest Expense. Interest expense for the three months ended June 30, 2009 decreased $6.2 million over the comparable period in 2008 primarily due to a $7.3 million increase in capitalized interest as well as a decrease in interest expense as a result of our debt reductions in the corresponding 2008 period, partially offset by the incremental interest expense associated with the issuance of our 8 ½% Senior Notes in June 2009.

Interest Income. Interest income for the three months ended June 30, 2009 decreased $4.2 million, or 84%, over the comparable period in 2008, due to the decrease in investment income earned as a result of significantly lower investment yields year-over-year. The decrease was also the result of maintaining lower average cash balances due to the repayment of debt and payments made for newbuild drillship construction projects, as compared to the comparable period in 2008.

Other Income (Expense), Net. Other income, net for the three months ended June 30, 2009 decreased $2.6 million over the comparable period in 2008, primarily due to a $2.8 million foreign exchange loss as compared with the same period in 2008.

Income Taxes. Our consolidated effective income tax rate for continuing operations for the three months ended June 30, 2009 was 15.2% compared with 22.1% for the three months ended June 30, 2008. The lower tax rate for the 2009 period was principally the result of the tax benefit related to the finalization of certain income tax returns and decreased profitability on some of our mid-water rigs operating in high tax rate jurisdictions, as well as much lower income than in the prior period in our mat-supported jackup segment operating in the United States and Mexico.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Revenues Excluding Reimbursable Revenues. Revenues excluding reimbursable revenues for the six months ended June 30, 2009 decreased $26.1 million, or 2%, over the comparable period in 2008. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for the six months ended June 30, 2009 decreased $5.5 million, or 20%, over the comparable period in 2008 primarily due to lower activity in our other segment.

Operating Costs. Operating costs for the six months ended June 30, 2009 increased $6.9 million, or 1%, over the comparable period in 2008. The increases were attributable to our deepwater, midwater and independent leg jackup segments, due primarily to higher repair and maintenance costs, equipment costs and labor costs. Operating costs for the Pride Venezuela were $9.9 million higher in the 2009 period as a result of unplanned repairs in 2009. Operating costs for the Pride Cabinda and the Pride Mexico were $11.2 million and $13.0 million higher, respectively. Both of these rigs worked for the entire period in 2009, while they had extended shipyard time in the 2008 period. In addition, rig labor costs were $15.6 million higher for these segments (excluding the rig labor costs associated with the Pride Cabinda and the Pride Mexico) in the 2009 period as compared to the 2008 period. Partially offsetting the increases, operating costs in our mat-supported jackup segment were $25.9 million lower as a result of the lower level of operating activity in the 2009 period. In addition, operating costs in our other segment decreased by $26.5 million due to the sale of our platform rigs in 2008 and the termination of two management contracts in the second half of 2008. Operating costs as a percentage of revenues, excluding reimbursables, were 52% and 50% for the six months ended June 30, 2009 and 2008, respectively.

Reimbursable Costs. Reimbursable costs for the six months ended June 30, 2009 decreased $6.7 million, or 25%, over the comparable period in 2008 primarily due to lower activity in our other segment.

Depreciation and Amortization. Depreciation expense for the six months ended June 30, 2009 increased $5.1 million, or 5%, over the comparable period in 2008. This increase relates to capital additions primarily in our midwater and deepwater segments.

General and Administrative. General and administrative expenses for the six months ended June 30, 2009 decreased $4.2 million, or 6%, over the comparable period in 2008. The decrease was due to a $7.2 million reduction related to costs incurred in the 2008 period for our ERP implementation and other related projects, a $2.8 million decrease in wages and related benefits, including special termination and retirement benefits paid in 2008, and a reduction of $4.7 million in expenses related to the ongoing investigation described under “—FCPA Investigation” above, partially offset by an increase of $7.9 million in costs related to the separation of our mat-supported jackup business and an increase of $1.5 million due to higher corporate facility rental expenses.

Gain on Sale of Assets, Net. We had net gain on sales of assets of $5.4 million for the six months ended June 30, 2009 primarily due to the recognition of the deferred gain on sale from the sale of our platform fleet in May 2008. We had net gain on sales of assets of $17.7 million for the six months ended June 30, 2008 primarily from such sale.

Interest Expense. Interest expense for the six months ended June 30, 2009 decreased $17.7 million over the comparable period in 2008 primarily due to a $10.5 million increase in capitalized interest and a net decrease of $6.4 million in interest expense as a result of our debt reductions in the corresponding 2008 period, partially offset by the incremental interest expense associated with the issuance of our 8 ½% Senior Notes in June 2009.

Interest Income. Interest income for the six months ended June 30, 2009 decreased $10.3 million, or 83%, over the comparable period in 2008, due to the decrease in investment income earned as a result of significantly lower investment yields year-over-year. The decrease was also the result of maintaining lower average cash balances due to the repayment of debt and payments made for newbuild drillship construction projects, as compared to the comparable period in 2008.

Other Income (Expense), Net. Other income, net for the six months ended June 30, 2009 decreased $9.3 million, or 93%, over the comparable period in 2008, due to an $11.4 million gain recorded in the first quarter of 2008 resulting from the sale of our 30% interest in a joint venture that operated several land rigs in Oman. In addition, we had a $1.7 million loss in 2008 for mark-to-market adjustments and cash settlements on interest rate swap and cap agreements for our drillship loan facility, which were extinguished in March 2008 in connection with the retirement of the facility.

Income Taxes. Our consolidated effective income tax rate for continuing operations for the six months ended June 30, 2009 was 16.3% compared with 23.7% for the six months ended June 30, 2008. The lower tax rate for the 2009 period was principally the result of the tax benefit related to the finalization of certain income tax returns and decreased profitability on some of our mid-water rigs operating in high tax rate jurisdictions, as well as much lower income than in the prior period in our mat-supported jackup segment operating in the United States and Mexico.

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.

During the six months ended June 30, 2009, we used cash on hand and cash flows generated from operations as our primary source of liquidity for funding our working capital needs, debt repayment and capital expenditures. In addition, on June 2, 2009 we issued $500 million aggregate principal amount of 8 ½% senior notes due 2019. We expect to use the net proceeds from this offering for general corporate purposes. We believe that our cash on hand, including the net proceeds from the notes offering, cash flows from operations and availability under our revolving credit facility will provide sufficient liquidity through 2009 to fund our working capital needs, scheduled debt repayments and anticipated capital expenditures, including progress payments for our four drillship construction projects. In addition, we will continue to pursue opportunities to expand or upgrade our fleet, which could result in additional capital investment. We may also in the future elect to return capital to our stockholders by share repurchases or the payment of dividends.

We may review from time to time possible expansion and acquisition opportunities relating to our business, which may include the construction or acquisition of rigs or acquisitions of other businesses in addition to those described in this quarterly report. Any determination to construct 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 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.

As discussed above, we have filed a Form 10 registration statement with the SEC with respect to the distribution to our stockholders of all of the shares of common stock of a subsidiary to be named Seahawk Drilling, Inc. that would hold, directly or indirectly, the assets and liabilities associated with our 20-rig mat-supported jackup business. For additional information about the spin-off, including the anticipated cash contribution to Seahawk, please read “—Recent Developments—Spin-off of Mat-Supported Jackup Business.”

Sources and Uses of Cash for the Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Cash flows provided by operating activities

Cash flows provided by operations were $374.6 million for the six months ended June 30, 2009 compared with $259.8 million for the comparable period in 2008. The increase of $114.8 million was primarily due to a reduction in our trade receivables partially offset by reductions in accounts payable and accrued expenses in 2009. Cash flows from operations include the effects of our discontinued operations, which provided $0.4 million and $4.3 million of operating cash flows for the six months ended June 30, 2009 and 2008, respectively.

Cash flows used in investing activities

Cash flows used in investing activities were $450.4 million for the six months ended June 30, 2009 compared with $215.5 million for the comparable period in 2008, an increase of $234.9 million. Purchases of property and equipment totaled $474.7 million and $506.6 million for the six months ended June 30, 2009 and 2008, respectively. The decrease was primarily due to the upgrade project for the Pride Mexico that was completed in March 2008. In addition, we received approximately $290 million of net proceeds in the 2008 period in connection with various assets sales.

Cash flows provided by financing activities

Cash flows provided by financing activities were $479.0 million for the six months ended June 30, 2009 compared with cash flows used in financing activities of $428.4 million for the comparable period in 2008, an increase of $907.4 million. The 2009 period included net proceeds of $492.4 million from the June 2009 notes offering, offset partially by $15.2 million of scheduled debt repayments. In 2008, our net cash used for debt repayments included $300 million to retire all of the outstanding 3¼% Convertible Senior Notes due 2033, $138.9 million to repay in full the outstanding amounts under our drillship loan facility and $15.2 million in scheduled debt repayments. We also received proceeds of $1.9 million and of $19.2 million from employee stock transactions in the six months ended June 30, 2009 and 2008, respectively.

Working Capital

As of June 30, 2009, we had working capital of $1,144.9 million compared with $849.6 million as of December 31, 2008. The increase in working capital is primarily due to the June 2009 notes offering, offset partially by expenditures incurred towards the construction of our four ultra-deepwater drillships.

Available Credit Facilities

In December 2008, we entered into a new $300 million unsecured revolving credit agreement with a group of banks maturing in December 2011. In July 2009, borrowing availability under the facility was increased to $320 million. Borrowings under the credit facility are available to make investments, acquisitions and capital expenditures, to repay and back-up commercial paper and for other general corporate purposes. We may obtain up to $100 million of letters of credit under the facility. The credit facility also has an accordion feature that would, under certain circumstances, allow us to increase the availability under the facility 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, 2009, there were no outstanding borrowings or letters of credit outstanding under the facility.

Other Outstanding Debt

As of June 30, 2009, 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

•

$212.1 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 2009, excluding our new drillship commitments, to be approximately $405 million, of which we have spent approximately $105 million in the first six months of 2009. These purchases are expected to be used primarily for various rig upgrades in connection with new contracts as contracts expire during the year along with other sustaining capital projects. With respect to our four ultra-deepwater drillships currently under construction, we made payments of $315 million in the first six months of 2009, with the total remaining costs estimated to be approximately $1.7 billion. We anticipate making additional payments for the construction of these drillships of approximately $390 million for the remainder of 2009, approximately $550 million in 2010, and approximately $765 million in 2011, following the rescheduling of $200 million of payments from 2010 to 2011. We expect to fund our construction obligations with respect to these rigs through available cash, cash flow from operations and borrowings under our revolving credit facility.

We anticipate making income tax payments of approximately $120 million to $135 million in 2009, of which $97.7 million has been paid through June 30, 2009.

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

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

Letters of Credit

We are contingently liable as of June 30, 2009 in the aggregate amount of $223.7 million under certain performance, bid and custom bonds and letters of credit. As of June 30, 2009, 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, 2008, 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, 2008. As of June 30, 2009, except with respect to the issuance and sale in June 2009 of $500 million aggregate principal amount of our 8 ½% Senior Notes due 2019 and the rescheduling of $200 million of payments on our drillship construction projects from 2010 to 2011, there were no material changes to this disclosure regarding our contractual obligations made in the annual report.

Accounting Pronouncements

In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements, which is an amendment of Accounting Research Bulletin No. 51. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. In addition, SFAS No. 160 requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent’s owners and the interests of the noncontrolling owners of a subsidiary. This statement is effective for the fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We adopted SFAS No. 160 on January 1, 2009 but its adoption did not have a material impact on our consolidated financial statements.

In April 2009, the FASB issued FASB Staff Position (“FSP”) SFAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, which amends the guidance in SFAS No. 141(R) to require contingent assets acquired and liabilities assumed in a business combination to be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the measurement period. If fair value cannot be reasonably estimated during the measurement period, the contingent asset or liability would be recognized in accordance with SFAS No. 5, Accounting for Contingencies, and FASB Interpretation (FIN) No. 14, Reasonable Estimation of the Amount of a Loss. Further, this FSP eliminated the specific subsequent accounting guidance for contingent assets and liabilities from Statement 141(R), without significantly revising the guidance in SFAS No. 141. However, contingent consideration arrangements of an acquiree assumed by the acquirer in a business combination would still be initially and subsequently measured at fair value in accordance with SFAS No. 141(R). This FSP is effective for all business acquisitions occurring on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted the provisions of SFAS No. 141(R) and FSP SFAS 141(R)-1 for business combinations with an acquisition date on or after January 1, 2009.

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;

•

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;

•

the proposed distribution to stockholders of our mat-supported jackup business, the timing thereof and the amount of the expected cash contribution to be made to the subsidiary prior to the distribution;

•

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;

•

expected costs for salvage and removal of the Pride Wyoming and expected insurance recoveries with respect to those costs and the damage to offshore structures caused by the loss of the rig;

•

business strategies;

•

expansion and growth of operations;

•

future exposure to currency devaluations or exchange rate fluctuations;

•

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

•

future operating results and financial condition; and

•

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

We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. These statements are subject to a number of assumptions, risks and uncertainties, including those described under “— FCPA Investigation” above, 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, 2008 and the following:

•

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

•

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

•

ability to adequately staff our rigs;

•

foreign exchange controls and currency fluctuations;

•

political stability in the countries in which we operate;

•

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

•

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

•

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

•

changes in laws or 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, 2008. 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 the Notes to Unaudited Consolidated Financial Statements 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, 2009 were effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The information set forth in Note 9 of the Notes to Unaudited Consolidated Financial Statements 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, 2008.

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

We are engaged in discussions with the DOJ and the SEC regarding a potential negotiated resolution of these matters, which could be settled during 2009 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. No amounts have been accrued related to any potential fines, sanctions, claims or other penalties, which could be material individually or in the aggregate, but an accrual could be made as early as the third quarter of 2009.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. There can be no assurance that these discussions 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 are subject to numerous governmental laws and regulations, including those that may impose significant costs and liability on us for environmental and natural resource damages.

Many aspects of our operations are affected by governmental laws and regulations that may relate directly or indirectly to the contract drilling and well servicing industries, including those requiring us to obtain and maintain specified permits or other governmental approvals and to control the discharge of oil and other contaminants into the environment or otherwise relating to environmental protection. Our operations and activities in the United States are subject to numerous environmental laws and regulations, including the Oil Pollution Act of 1990, the Outer Continental Shelf Lands Act, the Comprehensive Environmental Response, Compensation, and Liability Act and the International Convention for the Prevention of Pollution from Ships. Additionally, other countries where we operate have adopted, and could in the future adopt additional, environmental laws and regulations covering the discharge of oil and other contaminants and protection of the environment that could be applicable to our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and even criminal penalties, the imposition of remedial obligations, the denial or revocation of permits or other authorizations and the issuance of injunctions that may limit or prohibit our operations. We are currently subject to pending notices of assessment 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. In addition, we are currently subject to a pending administrative proceeding initiated by a government authority of Spain pursuant to which such government 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.

Laws and regulations protecting the environment have become more stringent in recent years and may in certain circumstances impose strict liability, rendering us liable for environmental and natural resource damages without regard to negligence or fault on our part. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others or for acts that were in compliance with all applicable laws at the time the acts were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or development drilling for oil and natural gas could materially limit future contract drilling opportunities or materially increase our costs or both. In addition, we may be required to make significant capital expenditures to comply with laws and regulations or materially increase our costs or both.

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 2009:

Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share	Total Number of Shares Purchased as Part of a Publicly Announced Plan (2)	Maximum Number of Shares That May Yet Be Purchased Under the Plan (2)






April 1-30, 2009	13,569	$19.84	N/A	N/A
May 1-31, 2009	414	$22.54	N/A	N/A
June 1-30, 2009	-	-	N/A	N/A
Total	13,983	$19.92	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.

Item 4. Submission of Matters to a Vote of Security Holders

Our annual meeting of stockholders was held in Houston, Texas on May 21, 2009 for the purpose of voting on the proposals described below. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934 and there was no solicitation in opposition to management’s solicitation.

Stockholders approved the election of eight directors, each to serve for a one-year term, by the following votes:

Name	For	Withheld
David A.B. Brown	89,142,537	55,456,617
Kenneth M. Burke	89,177,418	55,421,736
Archie W. Dunham	78,793,925	65,805,229
David A. Hager	89,179,139	55,420,015
Francis S. Kalman	89,191,037	55,408,117
Ralph D. McBride	67,211,027	77,388,127
Robert G. Phillips	89,193,539	55,405,615
Louis A. Raspino	89,155,594	55,443,560

Stockholders ratified the appointment of KPMG LLP as our independent registered public accounting firm for 2009 by the following vote:

For	143,897,247
Against	607,510
Abstain	70,518
Broker Non-Vote	23,880

Item 6. Exhibits***

4.1*		Second Supplemental Indenture dated as of June 2, 2009 by and between Pride and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A.), as Trustee.

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.

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101.CAL**		XBRL Taxonomy Extension Calculation Linkbase

101.REF**		XBRL Taxonomy Reference Linkbase

____________

*	Filed herewith.

**	To be furnished by amendment.

***

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.

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, 2009

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

Date: July 29, 2009

INDEX TO EXHIBITS

4.1*		Second Supplemental Indenture dated as of June 2, 2009 by and between Pride and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A.), as Trustee.

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.

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101.PRE**		XBRL Taxonomy Extension Presentation Linkbase

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101.CAL**		XBRL Taxonomy Extension Calculation Linkbase

101.REF**		XBRL Taxonomy Reference Linkbase

____________

*	Filed herewith.

**	To be furnished by amendment.

***

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Good

Pride International (PDE) Inactive 10-Q2009 Q2 Quarterly report

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