Form 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended September 30, 2010


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 (State or other jurisdiction of incorporation or organization)		76-0069030 (I.R.S. Employer Identification No.)

5847 San Felipe, Suite 3300
Houston, Texas (Address of principal executive offices)		77057 (Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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

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


		Outstanding as of
		November 1, 2010
Common Stock, par value $.01 per share		175,726,054

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Pride International, Inc.

Consolidated Balance Sheets
(In millions, except par value)


	September 30,			December 31,
	2010			2009
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	639.6		$	763.1
Trade receivables, net		201.6			211.9
Deferred income taxes		7.6			21.6
Other current assets		154.3			167.6

Total current assets		1,003.1			1,164.2

PROPERTY AND EQUIPMENT		7,152.3			6,091.0
Less: accumulated depreciation		1,326.4			1,200.7

Property and equipment, net		5,825.9			4,890.3
OTHER ASSETS, NET		90.5			88.4

Total assets	$	6,919.5		$	6,142.9

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt	$	30.3		$	30.3
Accounts payable		148.1			132.4
Accrued expenses and other current liabilities		274.3			339.7

Total current liabilities		452.7			502.4

OTHER LONG-TERM LIABILITIES		103.9			118.3

LONG-TERM DEBT, NET OF CURRENT PORTION		1,841.3			1,161.7

DEFERRED INCOME TAXES		65.8			102.7

STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value; 50.0 shares authorized; none issued		—			—
Common stock, $0.01 par value; 400.0 shares authorized; 176.8 and 175.5 shares issued; 175.7 and 174.6 shares outstanding		1.8			1.8
Paid-in capital		2,093.9			2,058.7
Treasury stock, at cost; 1.1 and 0.9 shares		(21.6	)		(16.4	)
Retained earnings		2,377.7			2,210.8
Accumulated other comprehensive income		4.0			2.9

Total stockholders’ equity		4,455.8			4,257.8

Total liabilities and stockholders’ equity	$	6,919.5		$	6,142.9

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
	September 30,
	2010			2009

REVENUES
Revenues excluding reimbursable revenues	$	337.8		$	379.5
Reimbursable revenues		8.4			6.6

		346.2			386.1


COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		213.0			210.6
Reimbursable costs		7.5			5.8
Depreciation and amortization		46.7			39.5
General and administrative, excluding depreciation and amortization		22.6			30.2
Loss (gain) on sales of assets, net		0.4			(0.1	)

		290.2			286.0


EARNINGS FROM OPERATIONS		56.0			100.1

OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		(6.5	)		—
Refinancing charges		(16.7	)		—
Interest income		1.1			0.6
Other expense, net		(6.1	)		(2.7	)


INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		27.8			98.0
INCOME TAXES		15.0			(18.1	)


INCOME FROM CONTINUING OPERATIONS, NET OF TAX		42.8			79.9
LOSS FROM DISCONTINUED OPERATIONS, NET OF TAX		(6.3	)		(44.3	)


NET INCOME	$	36.5		$	35.6


BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	0.24		$	0.45
Loss from discontinued operations		(0.04	)		(0.26	)

Net income	$	0.20		$	0.19

DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	0.24		$	0.45
Loss from discontinued operations		(0.04	)		(0.25	)

Net income	$	0.20		$	0.20

SHARES USED IN PER SHARE CALCULATIONS
Basic		175.7			173.5
Diluted		176.2			174.0

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)


	Nine Months Ended
	September 30,
	2010			2009

REVENUES
Revenues excluding reimbursable revenues	$	1,039.2		$	1,253.0
Reimbursable revenues		20.1			24.4

		1,059.3			1,277.4


COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		631.9			615.9
Reimbursable costs		16.9			21.6
Depreciation and amortization		133.4			118.3
General and administrative, excluding depreciation and amortization		77.7			85.3
Gain on sales of assets, net		(0.1	)		(0.5	)

		859.8			840.6


EARNINGS FROM OPERATIONS		199.5			436.8

OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		(6.5	)		(0.1	)
Refinancing charges		(16.7	)		—
Interest income		2.2			2.6
Other income (expense), net		5.6			(3.3	)


INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		184.1			436.0
INCOME TAXES		(2.9	)		(72.5	)


INCOME FROM CONTINUING OPERATIONS, NET OF TAX		181.2			363.5
LOSS FROM DISCONTINUED OPERATIONS, NET OF TAX		(14.3	)		(44.9	)


NET INCOME	$	166.9		$	318.6


BASIC EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	1.02		$	2.06
Loss from discontinued operations		(0.08	)		(0.26	)

Net income	$	0.94		$	1.80

DILUTED EARNINGS PER SHARE:
Income from continuing operations attributable to common shareholders	$	1.02		$	2.06
Loss from discontinued operations		(0.08	)		(0.26	)

Net income	$	0.94		$	1.80

SHARES USED IN PER SHARE CALCULATIONS
Basic		175.5			173.4
Diluted		176.0			173.7

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

Pride International, Inc.

Consolidated Statements of Cash Flows

(Unaudited)
(In millions)


	Nine Months Ended
	September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	166.9		$	318.6
Adjustments to reconcile net income to net cash from operating activities:
Gain on sale of Eastern Hemisphere land rigs		—			(5.4	)
Depreciation and amortization		133.4			155.8
Refinancing charges		12.3			—
Amortization and write-offs of deferred financing costs		5.2			1.6
Amortization of deferred contract liabilities		(40.3	)		(40.3	)
Impairment charges		—			33.4
Gain on sales of assets, net		(0.1	)		(0.5	)
Deferred income taxes		(20.3	)		(23.9	)
Excess tax benefits from stock-based compensation		(2.7	)		(1.0	)
Stock-based compensation		25.0			28.8
Other, net		2.0			0.6
Net effect of changes in operating accounts (See Note 12)		3.0			59.3
Change in deferred gain on asset sales and retirements		—			4.9
Increase in deferred revenue		12.7			0.6
Increase in deferred expense		(31.8	)		(0.4	)

NET CASH FLOWS FROM OPERATING ACTIVITIES		265.3			532.1
CASH FLOWS USED IN INVESTING ACTIVITIES:
Purchases of property and equipment		(1,049.1	)		(698.6	)
Reduction of cash from spin-off of Seahawk		—			(82.4	)
Proceeds from dispositions of property and equipment		1.3			7.3
Proceeds from the sale of Eastern Hemisphere land rigs, net		—			9.6

NET CASH FLOWS USED IN INVESTING ACTIVITIES		(1,047.8	)		(764.1	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of borrowings, including prepayment premiums		(534.6	)		(22.3	)
Proceeds from debt borrowings		1,200.0			498.2
Debt financing costs		(16.6	)		(6.2	)
Net proceeds from employee stock transactions		7.5			6.3
Excess tax benefits from stock-based compensation		2.7			1.0

NET CASH FLOWS FROM FINANCING ACTIVITIES		659.0			477.0
(Decrease) increase in cash and cash equivalents		(123.5	)		245.0
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		763.1			712.5

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	639.6		$	957.5

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 25 offshore rigs. We also have two deepwater drillships under construction.

Basis of Presentation

Our unaudited consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations. We believe that the presentation and disclosures herein are adequate to make the information not misleading. In the opinion of management, the unaudited consolidated financial information included herein reflects all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of our financial position, results of operations and cash flows for the interim periods presented. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2009. The results of operations for the interim periods presented herein are not necessarily indicative of the results to be expected for a full year or any other interim period.

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

Management Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Property and Equipment

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

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

During the first and second quarters of 2010, management determined that a triggering event had occurred for the Independent Leg Jackup asset group resulting from current and forecasted operating losses within the asset group. Management performed an undiscounted cash flow analysis for the group’s long-lived assets to determine if there was any impairment of the asset group and, as a result of this analysis, determined that no impairment was required.

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

Fair Value Accounting

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

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

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

Comprehensive Income

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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010			2009

Net Income	$	36.5	$	35.6		$	166.9		$	318.6
Other comprehensive gains (losses), net of tax
Foreign currency translation		1.9		0.5			1.8			2.2
Foreign currency hedges		0.7		(0.2	)		0.5			0.1
Defined benefit plan		—		—			(1.2	)		—

Comprehensive Income	$	39.1	$	35.9		$	168.0		$	320.9

Accounting Pronouncements

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

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

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

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

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

Reclassifications

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

NOTE 2. DISCONTINUED OPERATIONS AND OTHER DIVESTITURES

Discontinued Operations

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

Spin-off of Mat-Supported Jackup Business

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

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenues	$	—		$	30.8		$	—		$	189.4

Loss before taxes		(0.1	)		(59.5	)		(1.0	)		(65.3	)
Income taxes		(5.9	)		17.5			(5.7	)		18.0

Loss from discontinued operations	$	(6.0	)	$	(42.0	)	$	(6.7	)	$	(47.3	)

In connection with the spin-off, we made a cash contribution to Seahawk of approximately $47.3 million to achieve a targeted working capital for Seahawk as of May 31, 2009 of $85 million. We and Seahawk also agreed to indemnify each other for certain liabilities that may arise or be incurred in the future attributable to our respective businesses. During the third quarter of 2010, we recorded a charge to income tax expense for discontinued operations due to the allocation of additional foreign tax credits to Seahawk stemming from the finalization of our 2009 income tax return. As of September 30, 2010 and December 31, 2009, we had a receivable from Seahawk of $14.1 million and $18.8 million, respectively, which is included in “Other current assets,” pursuant to a transition services agreement and management agreements for the operation of the Pride Wisconsin and the Pride Tennessee in connection with the spin-off.

Other Divestitures

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

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

During the third quarter of 2007, we completed the disposition of our Latin America Land and E&P Services segments for $1.0 billion in cash. The purchase price was subject to certain post-closing adjustments for working capital and other indemnities. In December 2009, we filed suit against the buyer in the federal district court in the Southern District of New York to collect the final amount of the working capital adjustment payable by the buyer to us, plus interest, as determined in accordance with the purchase agreement, and the buyer made various counterclaims in the proceeding. All claims of the parties were settled in the first quarter of 2010, and the federal district court dismissed the claims with prejudice on March 10, 2010. From the closing date of the sale in the third quarter of 2007 through September 30, 2010, we recorded a total gain on disposal of $318.6 million, which included certain valuation adjustments for tax and other indemnities provided to the buyer and selling costs incurred by us. We have indemnified the buyer for certain obligations that may arise or be incurred in the future by the buyer with respect to the business. We believe it is probable that some of these indemnified liabilities will be settled with the buyer in cash. Our total estimated gain on disposal of assets includes an $8.3 million liability, based on our fair value estimates for the indemnities, and a $6.7 million asset for the cash value of tax benefits related to tax overpayments that the buyer will owe us when the benefits are realized. In the first quarter of 2010, we recorded a $6.8 million charge to the gain on disposal in connection with the re-measurement of a remaining indemnity that resulted from a foreign exchange fluctuation. The expected settlement dates for the remaining tax indemnities may vary from within one year to several years. Our final gain may be materially affected by the final resolution of these matters.

NOTE 3. PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:


	September 30,			December 31,
	2010			2009

Rigs and rig equipment	$	5,130.5		$	4,101.4
Construction-in-progress — newbuild drillships		1,690.6			1,682.4
Construction-in-progress — other		245.9			222.8
Other		85.3			84.4

Property and equipment, cost		7,152.3			6,091.0
Accumulated depreciation and amortization		(1,326.4	)		(1,200.7	)

Property and equipment, net	$	5,825.9		$	4,890.3

NOTE 4. DEBT

Senior Unsecured Revolving Credit Facility

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

The credit facility contains a number of covenants restricting, among other things, liens; indebtedness of our subsidiaries; mergers and dispositions of all or substantially all of our or certain of our subsidiaries’ assets; hedging arrangements outside the ordinary course of business; and sale-leaseback transactions. The facility also requires us to maintain certain financial ratios. The facility contains customary events of default, including with respect to a change of control.

Borrowings under the credit facility are available to make investments, acquisitions and capital expenditures, to repay and back-up commercial paper and for other general corporate purposes. We may obtain up to $100 million of letters of credit under the facility. As of September 30, 2010, there were no borrowings or letters of credit outstanding under the facility.

Notes Issuance and Notes Redemption

On August 6, 2010, we completed an offering of $900.0 million aggregate principal amount of our 6 7/8% Senior Notes due 2020 and $300.0 million aggregate principal amount of our 7 7/8% Senior Notes due 2040. The 2020 notes and the 2040 notes bear interest at 6.875% and 7.875%, respectively, per annum, payable semiannually.

The notes contain provisions that limit our ability and the ability of our subsidiaries, with certain exceptions, to engage in sale and leaseback transactions, create liens and consolidate, merge or transfer all or substantially all of our assets. Upon a specified change in control event that results in a ratings decline, we will be required to make an offer to repurchase the notes at a repurchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest through the applicable repurchase date. The notes of each series are subject to redemption, in whole at any time or in part from time to time, at our option, at a redemption price equal to the principal amount of the notes redeemed plus a make-whole premium. We will also pay accrued but unpaid interest to the redemption date.

On September 5, 2010, we redeemed all of our outstanding 7 3/8% Senior Notes due 2014 with a portion of the proceeds from the issuance of the 2020 notes and 2040 notes. The aggregate principal amount of $500.0 million was redeemed at a price of 102.458% of the principal amount, plus accrued and unpaid interest to the redemption date. As a result of the redemption of the 2014 notes, we recognized a charge of $16.4 million during the third quarter of 2010 related to the prepayment premium and write-off of unamortized debt issuance costs and discount related to the notes, which is included in “Refinancing charges” for the three and nine months ended September 30, 2010.

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

Debt consisted of the following:


	September 30,		December 31,
	2010		2009

Senior unsecured revolving credit facility	$	—	$	—
7 3/8% Senior Notes due 2014, net of uamortized discount of $1.4 million at December 31, 2009		—		498.6
8 1/2% Senior Notes due 2019, net of unamortized discount of $1.6 million and $1.7 million, respectively		498.4		498.3
6 7/8% Senior Notes due 2020		900.0		—
7 7/8% Senior Notes due 2040		300.0		—
MARAD notes, net of unamortized fair value discount of $1.5 million and $1.9 million, respectively		173.2		195.1

Total debt		1,871.6		1,192.0
Less: current portion of long-term debt		30.3		30.3

Long-term debt	$	1,841.3	$	1,161.7

NOTE 5. FAIR VALUE MEASUREMENTS

Fair Value of Financial Instruments

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, foreign currency forward contracts and debt. Our cash and cash equivalents, accounts receivable and accounts payable are by their nature short-term. As a result, the carrying value included in the accompanying consolidated balance sheets approximate fair value. The estimated fair value of our debt at September 30, 2010 and December 31, 2009 was $2,082.9 million and $1,307.6 million, respectively, which differs from the carrying amounts of $1,871.6 million and $1,192.0 million, respectively, included in our consolidated balance sheets. The fair value of our debt has been estimated based on quarter- and year-end quoted market prices.

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


				Quoted Prices		Significant			Significant
				in		Other			Unobservable
				Active Markets		Observable Inputs			Inputs
	Total			(Level 1)		(Level 2)			(Level 3)
September 30, 2010
Derivative Financial Instruments
Foreign currency forward contracts	$	0.4		$	—	$	0.4		$	—

December 31, 2009
Derivative Financial Instruments
Foreign currency forward contracts	$	(0.1	)	$	—	$	(0.1	)	$	—

The foreign currency forward contracts have been valued using a combined income and market-based valuation methodology based on forward exchange curves and credit. These curves are obtained from independent pricing services reflecting broker market quotes.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy or any changes in the valuation techniques used during the quarter ended September 30, 2010.

NOTE 6. DERIVATIVES AND FINANCIAL INSTRUMENTS

Cash Flow Hedging

We have a foreign currency hedging program to mitigate the change in value of forecasted payroll transactions and related costs denominated in euros. We are hedging a portion of these payroll and related costs using forward contracts. When the U.S. dollar strengthens against the euro, the decline in the value of the forward contracts is offset by lower future payroll costs. Conversely, when the U.S. dollar weakens, the increase in value of forward contracts offsets higher future payroll costs. When effective, these transactions should generate cash flows that directly offset the cash flow effect from changes in the value of our forecasted euro-denominated payroll transactions. The maximum amount of time that we are hedging our exposure to euro-denominated forecasted payroll costs is six months. The aggregate notional amount of these forward contracts, expressed in U.S. dollars, was $5.7 million at September 30, 2010.

All of our foreign currency forward contracts were accounted for as cash flow hedges under ASC Topic 815, Derivatives and Hedging. The fair market value of these derivative instruments is included in other current assets or accrued expenses and other current liabilities, with the cumulative unrealized gain or loss included in accumulated other comprehensive income in our consolidated balance sheet. The payroll and related costs that are being hedged are included in accrued expenses and other current liabilities in our consolidated balance sheet, with the realized gain or loss associated with the revaluation of these liabilities from euros to U.S. dollars included in other income (expense). Amounts recorded in accumulated other comprehensive income associated with the derivative instruments are subsequently reclassed into other income (expense) as earnings are affected by the underlying hedged forecasted transactions. The estimated fair market value of our outstanding foreign currency forward contracts resulted in an asset of approximately $0.4 million at September 30, 2010. Hedge effectiveness is measured quarterly based on the relative cumulative changes in fair value between derivative contracts and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings and recorded to other income (expense). We did not recognize a gain or loss due to hedge ineffectiveness in our consolidated statements of operations for the nine months ended September 30, 2010 related to these derivative instruments.

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


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

Net unrealized gain at end of period	$	0.4		$	0.2

NOTE 7. INCOME TAXES

In accordance with generally accepted accounting principles, we estimate the full-year effective tax rate from continuing operations and apply this rate to our year-to-date income from continuing operations. In addition, we separately calculate the tax impact of unusual items, if any. For the three months ended September 30, 2010 and 2009, our consolidated effective tax rate for continuing operations was (54.0%) and 18.5%, respectively. For the nine months ended September 30, 2010 and 2009, our consolidated effective tax rate for continuing operations was 1.6% and 16.6%, respectively. The lower tax rate for the 2010 period was principally the result of lower income from continuing operations in 2010, tax benefits related to the adjustment of intercompany pricing in the completion of our 2009 tax return during the third quarter of 2010, an increased proportion of income in lower tax jurisdictions, and the catch-up effect of our current lower annual projected tax rate.

NOTE 8. EARNINGS PER SHARE

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Income from continuing operations	$	42.8		$	79.9		$	181.2		$	363.5
Income from continuing operations allocated to non-vested share awards (participating securities)		(0.5	)		(1.2	)		(2.1	)		(5.6	)

Income from continuing operations -basic and diluted	$	42.3		$	78.7		$	179.1		$	357.9


Weighted average shares of common stock outstanding — basic		175.7			173.5			175.5			173.4
Stock options		0.4			0.5			0.4			0.3
Restricted stock awards		0.1			—			0.1			—

Weighted average shares of common stock outstanding — diluted		176.2			174.0			176.0			173.7

Income from continuing operations per share:
Basic	$	0.24		$	0.45		$	1.02		$	2.06
Diluted	$	0.24		$	0.45		$	1.02		$	2.06

For the three months ended September 30, 2010 and 2009, the calculation of weighted average shares of common stock outstanding — diluted excludes 0.9 million and 1.4 million, respectively, of shares of common stock issuable pursuant to outstanding stock options and certain restricted stock unit awards because their effect was anti-dilutive. For the nine months ended September 30, 2010 and 2009, the calculation of weighted average shares of common stock outstanding — diluted excludes 0.9 million and 2.6 million, respectively, of shares of common stock issuable pursuant to outstanding stock options and certain restricted stock unit awards because their effect was anti-dilutive.

NOTE 9. STOCK-BASED COMPENSATION

Our stock-based compensation plans provide for the granting or awarding of stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards and cash awards to directors, officers and other key employees. During the three months ended September 30, 2010, we granted 10,449 restricted stock unit awards to employees that vest ratably over three years with a weighted average grant-date fair value per share of $23.79. We did not grant any stock option awards or any restricted stock units with performance and market condition criteria during the three months ended September 30, 2010.

NOTE 10. COMMITMENTS AND CONTINGENCIES

FCPA Investigation

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

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

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

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

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

We have reached agreements with the DOJ and the SEC to settle these matters. We expect that documents reflecting the settlements could be filed by the DOJ and the SEC within a matter of days in the U.S. District Court for the Southern District of Texas, but the settlements require court approval. Under the terms of the contemplated settlement with the DOJ, it is expected that one of our foreign subsidiaries, Pride Forasol S.A.S., will plead guilty to certain FCPA-related charges. In addition, we will enter into a deferred prosecution agreement, under which FCPA-related charges will be deferred for a period of three years. If we remain in compliance with the terms of the deferred prosecution agreement throughout its term, the charges against us will be dismissed with prejudice. Under the agreement with the DOJ, the total contemplated fines are approximately $32.6 million. The terms of the contemplated settlement of civil FCPA charges with the SEC include an injunction against further violations of the FCPA and the payment of disgorgement and prejudgment interest totaling approximately $23.6 million. Neither of the contemplated settlements with the DOJ and SEC include the appointment of a compliance monitor. There can be no assurance that the court will accept the contemplated settlements or that the ultimate resolution of these matters will not involve fines and penalties that exceed our current estimate of $56.2 million, which we accrued in the fourth 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. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our company. For additional information regarding a stockholder demand letter and derivative cases with respect to these matters, please see the discussion below under “—Demand Letter and Derivative Cases.” In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets. While we have made an accrual in anticipation of a possible resolution with the DOJ and SEC as discussed above, no amounts have been accrued related to any potential fines, sanctions, claims or other penalties referenced in this paragraph, which could be material individually or in the aggregate.

We cannot currently predict what actions a court may take regarding the contemplated settlements with the DOJ and the SEC, nor can we predict what, if any, actions may be taken by any other applicable government or other authorities or our customers or other third parties or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.

Arbitration Matter

In March 2002, Pride Offshore, Inc. (now Seahawk Drilling, Inc.) entered into contracts with BP America Production Co. to design, engineer, manage construction of and commission, as well as operate the drilling package on, the Mad Dog, a platform owned by BP America in the U.S. Gulf of Mexico. In 2004, the drilling package was accepted by BP America, and Pride Offshore’s work under the operation contract commenced. In September 2008, the drilling package was destroyed and the platform was damaged in Hurricane Ike. In September 2009, BP America and an affiliate, on behalf of itself and its joint venture partners, filed an arbitration notice under the contracts, claiming that Pride Offshore breached its express and implied warranties under the construction contract and is liable for fault and gross fault in performing the contracts. At the time, BP America alleged damages in excess of $10 million, with no further specificity. The parties engaged in mediation of the claims in May 2010. Also in May 2010, BP America claimed damages of $282 million for the loss of the drilling package and $19 million for damage to the platform. BP America also alleged loss of production, without specifying an amount. The parties did not resolve the matter through mediation in May and resumed the arbitration process; however, they have recently stayed the arbitration until November 8, 2010 to again attempt to reach a settlement.

Under our master separation agreement with Seahawk entered into at the time of the Seahawk spin-off in August 2009, we agreed to assume any obligations arising from the BP America contracts discussed above, which would include potential obligations arising from the construction of the drilling package. Although our insurance underwriters have reserved the right to raise coverage issues, we expect the claims generally to be covered under applicable insurance policies. We believe BP America’s claims will be barred or substantially limited by the limitation of liability and indemnity provisions of the contracts. We intend to continue to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of this matter to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter. As of September 30, 2010, we have an accrual for potential liability related to this matter and a receivable of approximately the same amount under our insurance policies. We believe that the matter has not adversely affected, and is not likely to adversely affect, our relationship with BP America in any material respect.

Environmental Matters

We are currently subject to pending notices of assessment issued from 2002 to 2010 pursuant to which governmental authorities in Brazil are seeking fines in an aggregate amount of approximately $1.4 million, based on exchange rates as of September 30, 2010, for releases of drilling fluids from rigs operating offshore Brazil. We are contesting these notices. We intend to defend ourselves vigorously and, based on the information available to us at this time, we do not expect the outcome of these assessments to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these assessments. As of September 30, 2010, we have an accrual of $1.4 million for potential liability related to these matters.

We are currently subject to a pending administrative proceeding initiated in July 2009 by a governmental authority of Spain pursuant to which such governmental authority is seeking payment in an aggregate amount of approximately $4 million for an alleged environmental spill originating from the Pride North America while it was operating offshore Spain. We expect to be indemnified for any payments resulting from this incident by our client under the terms of the drilling contract. The client has posted guarantees with the Spanish government to cover potential penalties. In addition, a criminal investigation of the incident was initiated by a prosecutor in Tarragona, Spain in July 2010, and the administrative proceedings have been suspended pending the outcome of this investigation. We do not know at this time what, if any, involvement we may have in this investigation. We intend to defend ourselves vigorously in the administrative proceeding and any criminal investigation of us and, based on the information available to us at this time, we do not expect the outcome of the proceedings to have a material adverse effect on our financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of the proceedings.

Demand Letter and Derivative Cases

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

Subsequent to the receipt of the demand letter, on October 14, 2009, Mr. Arnold filed suit in the state court of Harris County, Texas against us and certain of our current and former officers and directors. The lawsuit, like the demand letter, alleged that the individual defendants breached their fiduciary duties to us related to the issues described above under “—FCPA Investigation.” Among other remedies, the lawsuit sought damages in an unspecified amount and equitable relief against the individual defendants, along with an award of attorney fees and other costs and expenses to the plaintiff. On October 16, 2009, the plaintiff dismissed the lawsuit without prejudice, but the demand letter referenced above remains in effect.

On April 14, 2010, Edward Ferguson, a purported stockholder of Pride, filed a derivative action in the state court of Harris County, Texas against all of our current directors and us, as nominal defendant. The lawsuit alleges that the individual defendants breached their fiduciary duties to us related to the issues described above under “—FCPA Investigation.” Among other remedies, the lawsuit seeks damages in an unspecified amount and equitable relief against the individual defendants, along with an award of attorney fees and other costs and expenses to the plaintiff. On April 15, 2010, Lawrence Dixon, another purported stockholder, filed a substantially similar lawsuit in the state court of Harris County, Texas against the same defendants. These two lawsuits have been consolidated, and the parties agreed on a deferral of the matter of up to 120 days to await further developments in the FCPA investigation. That deferral has now expired. The parties are negotiating a further deferral and plan to report to the state court regarding their positions on such further deferral of the lawsuits.

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

Loss of Pride Wyoming

In September 2008, the Pride Wyoming, a 250-foot slot-type jackup rig owned by Seahawk and operating in the U.S. Gulf of Mexico, was deemed a total loss for insurance purposes after it was severely damaged and sank as a result of Hurricane Ike. All proceeds related to the insured value of the rig were received in 2008. Costs for removal of the wreckage have been and are expected to continue to be covered by our insurance. Under the master separation agreement between us and Seahawk, Seahawk will be responsible for any removal costs, legal settlements and legal costs associated with the Pride Wyoming not covered by insurance. At Seahawk’s request, we will be required to finance, on a revolving basis, some or all of the costs for removal of the wreckage and salvage operations until receipt of insurance proceeds. In May 2010, Seahawk requested that we pay an invoice in the amount of $6.8 million for a portion of the removal of the wreckage. We paid the invoice and were reimbursed for the entire amount under our insurance policies in the third quarter of 2010. In September 2010, at Seahawk’s request, we paid another invoice in the amount of $831,000 related to the removal of the wreckage, which we have recorded as a receivable based on a claim of the same amount that we made under our insurance policies.

Seahawk Tax-Related Credit Support

In 2006, 2007 and 2009, Seahawk received tax assessments from the Mexican government related to the operations of certain of Seahawk’s subsidiaries. Seahawk is responsible for these assessments following the spin-off. Pursuant to local statutory requirements, Seahawk has provided and may provide additional surety bonds, letters of credit, or other suitable collateral to contest these assessments. Pursuant to a tax support agreement between us and Seahawk, we have agreed, at Seahawk’s request, to guarantee or indemnify the issuer of any such surety bonds, letters of credit, or other collateral issued for Seahawk’s account in respect of such Mexican tax assessments made prior to the spin-off date. The amount of such collateral could total up to approximately $156.5 million, based on exchange rates as of September 30, 2010. Beginning on July 31, 2012, on each subsequent anniversary thereafter, and on August 24, 2015, Seahawk will be required to provide substitute credit support for a portion of the collateral guaranteed or indemnified by us, so that our obligations are terminated in their entirety by August 24, 2015. Pursuant to the tax support agreement, Seahawk is required to pay us a fee based on the actual credit support provided. On September 15, 2010, Seahawk requested that we provide credit support for four letters of credit issued for the appeals of four of Seahawk’s tax assessments. The amount of the request totaled approximately $48.1 million, based on exchange rates as of September 30, 2010. On October 28, 2010, we provided credit support in satisfaction of this request.

Former Amethyst Joint Venture Litigation

Prior to March 2001, we had an approximately 30% interest in joint venture companies organized to construct, own and operate four deepwater semisubmersible drilling rigs, later named the Pride Carlos Walter, Pride Brazil, Pride Portland and Pride Rio de Janeiro. In January 2000, the joint venture partner commenced litigation against Petróleo Brasileiro S.A. through various controlled companies, including the four rig-owning joint venture companies, challenging the cancellation of certain drilling contracts related to six rigs, including the four rigs listed above. We acquired our former joint venture partner’s interest in certain of the joint venture companies, including the four rig-owning companies, in separate transactions in March 2001 and November 2006. During this period and at the time of the November 2006 acquisition, we assigned all of our rights and interests in the Petrobras litigation to the joint venture partner, and the joint venture partner agreed (i) to indemnify us for any liability arising from the litigation and (ii) to cause our subsidiaries to be removed from the litigation if, and as soon as, such removal was possible without materially adversely affecting, in the partner’s reasonable opinion, the partner’s profile for recovery of damages under such litigation. In August 2010, we entered into an agreement to transfer for a nominal amount our interests in the four subsidiaries that are parties to the litigation. The transfer of two of the subsidiaries was consummated in September 2010, and the transfer of the remaining two subsidiaries was consummated in November 2010. At the time of transfer, the subsidiaries had no ownership interest in the rigs or any other material assets. After completion of the transfers, we no longer are parties to the litigation. No amounts have been accrued related to the matter. Because the litigation is being pursued by the former joint venture partner and not by us, we believe that it has not adversely affected, and is not likely to adversely affect, our relationship with Petrobras in any material respect. We currently have eight rigs contracted to Petrobras, including the four rigs named above.

Other

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

In the normal course of business with customers, vendors and others, we have entered into letters of credit and surety bonds as security for certain performance obligations that totaled approximately $487.1 million at September 30, 2010. These letters of credit and surety bonds are issued under a number of facilities provided by several banks and other financial institutions.

NOTE 11. SEGMENT AND ENTERPRISE-RELATED INFORMATION

We organize our reportable segments based on water depth operating capabilities of our drilling rigs. Our reportable segments include Deepwater, which consists of our drillships and semisubmersible rigs capable of drilling in water depths of 4,500 feet and greater; Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less; and Independent Leg Jackup, which consists of our jackup rigs capable of operating in water depths up to 300 feet. We also manage the drilling operations for two deepwater rigs, which are included in a non-reported operating segment along with corporate costs and other operations. The accounting policies for our segments are the same as those described in Note 1 of our Consolidated Financial Statements.

Summarized financial information for our reportable segments are as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Deepwater revenues:
Revenues excluding reimbursables	$	212.1		$	189.9		$	649.0		$	634.4
Reimbursable revenues		4.1			1.9			10.6			10.7

Total Deepwater revenues		216.2			191.8			659.6			645.1

Midwater revenues:
Revenues excluding reimbursables		86.1			96.8			269.0			338.9
Reimbursable revenues		0.1			1.4			0.7			4.8

Total Midwater revenues		86.2			98.2			269.7			343.7

Independent Leg Jackups revenues:
Revenues excluding reimbursables		24.5			72.6			76.9			220.7
Reimbursable revenues		0.2			0.2			1.0			0.6

Total Independent Leg Jackups revenues		24.7			72.8			77.9			221.3

Other		19.0			21.7			51.8			65.5
Corporate		0.1			1.6			0.3			1.8

Total revenues	$	346.2		$	386.1		$	1,059.3		$	1,277.4


Earnings (loss) from continuing operations:
Deepwater	$	66.9		$	71.8		$	237.4		$	300.9
Midwater		12.5			25.7			56.1			121.1
Independent Leg Jackups		(0.2	)		32.6			(13.5	)		102.3
Other		2.1			1.6			3.7			3.9
Corporate		(25.3	)		(31.6	)		(84.2	)		(91.4	)

Total	$	56.0		$	100.1		$	199.5		$	436.8


Capital expenditures:
Deepwater	$	360.1		$	195.5		$	949.9		$	620.3
Midwater		24.7			10.5			64.8			25.6
Independent Leg Jackups		3.8			2.5			17.0			9.7
Other		0.8			10.1			1.5			12.1
Corporate		4.3			5.3			15.9			18.3
Discontinued operations		—			—			—			12.6

Total	$	393.7		$	223.9		$	1,049.1		$	698.6


Depreciation and amortization:
Deepwater	$	24.7		$	19.0		$	67.4		$	56.8
Midwater		13.2			11.3			37.7			34.0
Independent Leg Jackups		7.0			7.3			23.0			21.3
Other		0.1			0.1			0.2			0.3
Corporate		1.7			1.8			5.1			5.9

Total	$	46.7		$	39.5		$	133.4		$	118.3

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


	September 30,		December 31,
	2010		2009
Total long-lived assets:
Deepwater	$	4,728.0	$	3,836.1
Midwater		720.7		680.5
Independent Leg Jackups		258.1		261.2
Other		16.7		23.1
Corporate		102.4		89.4

Total	$	5,825.9	$	4,890.3

For the three months ended September 30, 2010 and 2009, we derived 93% and 96%, respectively, of our revenues from countries outside of the United States. For the nine months ended September 30, 2010 and 2009, we derived 96% and 97%, respectively, of our revenues from countries outside of the United States.

Significant Customers

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Petroleos Brasileiro S.A.		40	%		35	%		39	%		30	%
Total S.A.		20	%		16	%		19	%		15	%
BP America and affiliates		11	%		3	%		13	%		3	%

NOTE 12. OTHER SUPPLEMENTAL INFORMATION

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


	Nine Months Ended
	September 30,
	2010			2009
Decrease (increase) in:
Trade receivables	$	10.3		$	47.0
Other current assets		34.6			6.7
Other assets		26.8			(19.5	)
Increase (decrease) in:
Accounts payable		(5.5	)		(30.9	)
Accrued expenses		(46.1	)		50.7
Other liabilities		(17.1	)		5.3

Net effect of changes in operating accounts	$	3.0		$	59.3


Cash paid during the year for:
Interest	$	70.3		$	44.7
Income taxes		32.8			112.0
Change in capital expenditures in accounts payable		21.0			33.2

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 September 30, 2010 and for the three and nine months ended September 30, 2010 and 2009 included elsewhere herein, and with our annual report on Form 10-K for the year ended December 31, 2009. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A of our annual report and Item 1A of Part II of our quarterly report on Form 10-Q for the quarter ended June 30, 2010 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 November 3, 2010, we operated a fleet of 25 rigs, consisting of four deepwater drillships, 12 semisubmersible rigs, seven independent leg jackups and two managed deepwater drilling rigs. We also have two deepwater drillships under construction. Our customers include major integrated oil and natural gas companies, state-owned national oil companies and independent oil and natural gas companies. Our competitors range from large international companies offering a wide range of drilling services to smaller companies focused on more specific geographic or technological areas.

Our primary strategic focus is on ownership and operation of floating offshore rigs, particularly deepwater rigs. Although crude oil prices have declined from the record levels reached in mid-2008 and the current market for deepwater drilling services remains uncertain in the near term, we believe the long-term prospects for deepwater drilling are positive given that the expected growth in oil consumption from developing nations, limited growth in crude oil supplies and high depletion rates of mature oil fields, together with geologic successes, improving access to promising offshore areas and new, more efficient technologies, including enhanced reservoir recovery techniques, will continue to be catalysts for the long-term exploration and development of deepwater fields. Since 2005, we have invested or committed to invest over $3.8 billion in the expansion of our deepwater fleet, including four new ultra-deepwater drillships, two of which were delivered in the first and third quarters of 2010 and two of which are under construction with expected delivery dates in the first and fourth quarters of 2011. Three of these new drillships have multi-year contracts at favorable rates. Since 2005, we also have disposed of non-core assets, generating $1.6 billion in proceeds, enabling us to increasingly focus our financial and human capital on deepwater drilling. In addition, on August 24, 2009, we completed the spin-off of Seahawk Drilling, Inc., which holds the assets and liabilities that were associated with our mat-supported jackup rig business.

With the tendency for deepwater drilling programs to be more insulated from short-term commodity price fluctuations, we expect that the deepwater market will outperform other offshore drilling market sectors over the long term. In addition, an increasing focus on deepwater prospects by national oil companies, whose activities are less sensitive to general economic factors, serve to provide further stability in the deepwater sector. However, the Deepwater Horizon incident and its consequences, as discussed further below, have increased the near-term uncertainty in the sector. Our contract backlog at September 30, 2010 totaled $6.4 billion and was comprised primarily of contracts for our deepwater rigs awarded by large integrated oil and national oil companies.

Recent Developments

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

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

Deep Ocean Ascension and Deep Ocean Clarion

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

On September 23, 2010, we took delivery of our second new ultra-deepwater drillship, the Deep Ocean Clarion. The Deep Ocean Clarion is currently in the mobilization period to the U. S. Gulf of Mexico where it is expected to commence a five-year contract with BP E&P late in the first quarter of 2011. We are currently working with BP E&P to finalize the acceptance plan for the Deep Ocean Clarion, which is expected to commence in January 2011. The acceptance process primarily involves testing of rig functionality, crew competency and safety features. The contract provides that our right to receive dayrate commences upon satisfactory completion of acceptance testing. The contract does not currently require the acceptance testing to be completed by a specified date, and BP E&P does not have the right to cancel the contract for the failure to meet acceptance criteria by a specified date.

Due to regulatory changes that have created potential delays and uncertainty regarding the resumption of drilling in the U.S. Gulf of Mexico, BP E&P may be unable to commence drilling operations with the Deep Ocean Clarion in the U.S. Gulf of Mexico according to its original schedule. In such case, and pursuant to the contract, BP E&P may request to change the drilling location to outside of the U.S. Gulf of Mexico or to pay the contractual standby dayrate, which approximates the operating dayrate for the drillship. The contract provides for worldwide use of the rig. BP E&P may also choose to exercise the contract’s termination for convenience clause, under which BP E&P would be required to provide a make-whole payment to us that approximates the present value of the cash margin that would have been earned over the life of the contract.

BP E&P owns a 65% working interest and is the operator of the exploration well associated with the Deepwater Horizon incident discussed below. While we currently expect BP E&P to perform its obligations under the drilling contracts for the Deep Ocean Ascension and the Deep Ocean Clarion, we cannot predict what actions BP E&P might attempt to take under the contracts or whether it ultimately will be able to perform its obligations in light of the incident and resulting spill. Our contracts with BP E&P do not include a written parent company guarantee. If BP E&P fails to perform under the contracts, the drillships could be idle for an extended period of time. In that case, our revenues and profitability could be materially reduced if we are unable to secure new contracts on substantially similar terms, or at all.

U.S. Gulf of Mexico

In response to the April 20, 2010 explosion and fire on the Deepwater Horizon and the resulting oil spill, the Bureau of Ocean Energy Management, Regulation and Enforcement of the U.S. Department of the Interior, at the time known as the Minerals Management Service (“BOEM”), implemented a moratorium on certain drilling activities in the U.S. Gulf of Mexico until November 30, 2010. On October 12, 2010, the Secretary of the Interior directed the BOEM to lift the moratorium subject to certain specified conditions. During the pendency of the moratorium, the BOEM implemented various environmental, technological and safety measures intended to improve offshore safety systems and environmental protection. The newly issued safety regulations require operators to, among other things, submit independent third-party reports on the design and operation of blowout preventers (“BOPs”) and other well control systems, and conduct tests on the functionality of well control systems. Additional regulations address new

standards for certain equipment involved in the construction of offshore wells, especially BOPs, and require operators to implement and enforce a safety and environmental management system including regular third-party audits of safety procedures and drilling equipment to insure that offshore rig personnel and equipment remain in compliance with the new regulations. Prior to the resumption of drilling following the moratorium, each operator is required to demonstrate that it has in place written and enforceable procedures, pursuant to applicable regulations, that ensure containment in the event of a deepwater blowout. We cannot currently predict the rate at which new well permits will be issued or the rate at which rigs will be allowed to return to work once compliance with the new regulations has been demonstrated. We believe, however, that the process followed by the BOEM to review and approve a well permit application by our clients will be protracted relative to past experience, resulting in significant delays in the resumption of drilling in deepwater U.S. Gulf of Mexico that could persist well into 2011.

The U.S. Gulf of Mexico represents one of three established deepwater drilling basins in the world and currently accounts for more than 20% of the industry’s deepwater rig capacity. The region is a vital contributor to the economy in the United States, providing strong hydrocarbon production growth potential and significant employment opportunities. Despite the economic importance of the region, the deepwater drilling moratorium, and the potential for significant delays in receiving drilling permits following the moratorium, has created significant uncertainty regarding the outlook for the region and possible implications for regions outside of the U.S. Gulf of Mexico. Due to such uncertainty, some contract drillers and operators with floating rigs located in the region may choose to relocate the units to other international drilling areas. Through October 2010, four of the 33 floating rigs operating in the U.S. Gulf of Mexico at the time of the incident have secured new drilling assignments and will relocate to international locations. Should there be significant delays in the issuance of drilling permits or in allowing rigs to operate upon demonstration of compliance with new regulations or should additional regulations and government oversight, operating procedures and the possibility of increased legal liability be viewed by our clients as a significant impairment to expected economic returns on projects in the region, additional floating rigs could depart the U.S. Gulf of Mexico, with fewer clients operating in the region. As a result, a more challenging business environment could develop in the international sector, characterized by increased supply of rig capacity and declining dayrates.

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

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

Except as described above under “Deep Ocean Ascension and Deep Ocean Clarion,” we do not currently have any rigs operating in the U.S. Gulf of Mexico. However, we have been notified by our customer Petrobras that the U.S. Gulf of Mexico is being considered as the initial area of operations for the Deep Ocean Mendocino, our third new ultra-deepwater drillship. The rig is scheduled for delivery from the shipyard in the first quarter of 2011.

Spin-off of Mat-Supported Jackup Business

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

Investments in Deepwater Fleet

In addition to the Deep Ocean Ascension and Deep Ocean Clarion discussed above, we also have agreements for the construction of two additional ultra-deepwater drillships, the Deep Ocean Mendocino and Deep Ocean Molokai. These rigs have scheduled delivery dates in the first and fourth quarters of 2011, respectively. Including amounts already paid, commissioning and testing, we expect total costs for these two remaining construction projects to be approximately $1.5 billion, excluding capitalized interest. Through September 30, 2010, we have spent approximately $740 million on these two projects. We are scheduled to commence a five-year drilling contract for the Deep Ocean Mendocino following completion of construction, mobilization of the rig to its initial operating location and customer testing and acceptance. Although we currently do not have a drilling contract for the Deep Ocean Molokai, we expect that the long-term demand for deepwater drilling capacity in established and emerging basins should provide us with opportunities to contract the rig prior to its delivery date.

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

FCPA Investigation

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

We cannot currently predict what actions a court may take regarding the contemplated settlements with the DOJ and the SEC, nor can we predict what, if any, actions may be taken by any other applicable government or other authorities or our customers or other third parties, or the effect the actions may have on our results of operations, financial condition or cash flows, on our consolidated financial statements or on our business in the countries at issue and other jurisdictions.

Our Business

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

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

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

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

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

Our industry has traditionally been affected by shortages of, and competition for, skilled rig crew personnel during periods of high levels of activity. Even as overall industry activity declines, we expect these personnel shortages to continue, especially in the Deepwater segment, due to the number of newbuild deepwater rigs expected to be delivered through 2013 and the need for highly skilled personnel to operate these rigs. To better retain and attract skilled rig personnel, we offer competitive compensation programs and have increased our focus on training and management development programs. Following an increase in 2009, labor costs have continued to increase in 2010, especially for skilled personnel in certain geographic locations, such as Brazil, Angola and the United States. An increase in labor costs during 2010 has been most pronounced in the Deepwater segment.

Beginning in 2005, the demand for contract drilling services increased significantly, resulting in increased demand for oilfield equipment and spare parts. This increased demand, when coupled with the consolidation of equipment suppliers, resulted in longer order lead times to obtain critical spare parts and other equipment components essential to our business, along with higher repair and maintenance costs and longer out-of-service time for major repair and upgrade projects. We maintain higher levels of critical spare parts in an effort to minimize unplanned downtime. With the decline in prices for steel and other key inputs that started in 2009 and the slow return in the level of business activity for 2010, we have seen some softening of lead times and pricing for spare parts and equipment during 2010.

Crude oil prices have traded in the range of $65 to $87 per barrel for more than a year, and have averaged approximately $78 per barrel through the first nine months of 2010. Crude oil prices were $34 per barrel in February 2009, which followed the onset of the global financial crisis, deteriorating global economic fundamentals and the resulting drop in crude oil demand in a number of the world’s largest oil consuming nations. These factors had a negative impact on customer demand for offshore rigs throughout 2009. While the initial months of 2010 were characterized by a similar pattern of caution from many operators toward new exploration and production spending commitments, evidence was present that supported increased spending with a number of new drilling programs commencing in 2011 and beyond, largely supported by operators’ increasing confidence in the re-establishment of global economic growth and the sustainability of crude oil prices. However, following the April 20, 2010 Deepwater Horizon incident in the U.S. Gulf of Mexico and the subsequent moratorium on deepwater drilling in the region, a new level of uncertainty has once again developed,

with operators choosing to delay the commencement of certain projects in the U.S. Gulf of Mexico and other regions pending further clarity on a number of industry issues. Worldwide offshore fleet utilization remained flat at approximately 75% at September 30, 2010 compared to 75% at December 31, 2009 and 75% at September 30, 2009. Utilization for the industry’s deepwater fleet has historically been less sensitive to the extreme fluctuations experienced within the shallow water market even during market downturns. However, the timing of the increased spending is expected to remain uncertain until operators have gained more clarity concerning the long-term implications to our industry of the Deepwater Horizon incident, including an understanding of the impact of new operating regulations and government oversight. Also, operators will need to be confident in stronger oil market fundamentals supported by broadening global economic improvement, leading to increased crude oil demand, especially among member countries of the Organization for Economic Co-operation and Development.

We believe that long-term market conditions for offshore drilling services are supported by sound fundamental factors but that future demand for our rigs in the worldwide market is uncertain in the short-term due to recent events in the U.S. Gulf of Mexico and its consequences. We expect the long-term global demand for deepwater contract drilling services to be driven by growing worldwide demand for crude oil and natural gas as global populations expand and economic growth accelerates, along with an increased focus by oil and natural gas companies on deepwater offshore prospects and increased global participation by national oil companies. Customer requirements for deepwater drilling capacity have grown since 2005 as the successful results in exploration drilling, especially since the late-1990s, have led to numerous prolonged field development programs around the world. This success has contributed to the demand for a number of our deepwater assets by our clients through the next decade, especially those rigs that are capable of operating in water depths of 6,000 feet and greater and that possess advanced well construction features leading to increased drilling efficiencies. Geological successes in exploratory markets, such as the numerous discoveries to date in the pre-salt formation offshore Brazil, the lower tertiary trend in the U.S. Gulf of Mexico and deeper waters offshore Angola, along with the continued development of a number of deepwater projects in each of these regions, are expected to produce long-term growing demand from clients for deepwater rigs. During 2009, operators announced a record 25 deepwater discoveries covering an expanding number of offshore basins, such as Ghana, pre-salt Brazil and Sierra Leone, further supporting the long-term sustainability of deepwater drilling demand. An additional 26 deepwater discoveries have been announced since the beginning of 2010, establishing another record year. Announced discoveries in 2010 include a discovery offshore Mozambique in East Africa, representing the initial deepwater well drilled offshore in this emerging province. Additional exploration drilling opportunities offshore East Africa are expected to develop in the future with client interest being expressed offshore Tanzania and Kenya. In addition, international oil companies are experiencing greater access to other promising areas offshore, such as India, Malaysia, Australia, Sao Tomé, Príncipe, Liberia, Gabon and the Black Sea. We anticipate that the combination of drilling successes, greater access to offshore basins, enhanced hydrocarbon recovery methods and continued advances in offshore drilling technology, which support increased efficiency in field development efforts like parallel drilling activities, will support the long-term outlook for deepwater rig demand. However, the possible increase in the international rig supply resulting in part from the drilling moratorium in the U.S. Gulf of Mexico, as some rigs are relocated to other regions, has created some uncertainty in demand for our deepwater rigs in the short-term.

Our deepwater fleet currently operates in Brazil, West Africa and the Mediterranean Sea. As described above under “Recent Developments,” the Deep Ocean Ascension is currently in the U.S. Gulf of Mexico and has completed its acceptance testing and is currently on the special standby dayrate awaiting instructions from our client regarding an initial drilling location. We took delivery of the Deep Ocean Clarion in September 2010, and the rig is currently in transit to the U.S. Gulf of Mexico where it is expected to commence a five-year contract with BP E&P late in the first quarter of 2011, following customer testing and acceptance. Including rig days for our two remaining drillships currently under construction, based upon their scheduled delivery dates, we currently have 100% of our available rig days in the last quarter of 2010 contracted for our deepwater fleet, with 83% in 2011, 67% in 2012 and 55% in 2013. Since an increase in customer demand for deepwater drilling rigs began in 2005, a high percentage of the industry’s deepwater fleet of 133 units accumulated large contract backlogs and remained under contract through September 30, 2010. This high customer demand led to a steep rise in deepwater rig dayrates, which peaked above $600,000 per day for some multi-year contracts awarded in 2008. Although declines in dayrates have occurred from peak levels, recent contract awards for deepwater rigs capable of drilling in greater than 7,000 feet of water and available in 2010 have remained above $400,000 per day. These dayrates have been supported by strong geologic success, especially in Brazil, West Africa, the U.S. Gulf of Mexico and some of the new and emerging deepwater regions, which have led to a growing number of commercial discoveries.

In Brazil, exploration drilling in the country’s prolific pre-salt formation has found numerous crude oil deposits of significant size residing more than 185 miles offshore and in up to 7,000 feet of water in the Santos Basin. Results of recent appraisal wells to define the potential size of these fields have confirmed the magnitude of the hydrocarbon complex. The successful drilling results in Brazil and aggressive exploration calendar have resulted in an announced exploration and production spending plan by Petrobras, the national oil company of Brazil, of over $200 billion from 2010 to 2014 to support development of the pre-salt formation and other global interests. The spending plan includes the need for 40 or more incremental deepwater rigs to be deployed in the numerous pre-salt fields discovered to date. Petrobras contracted 12 of the 40 rigs in 2008 from the international market and is currently engaged in a process to acquire up to 28 more rigs through construction of some rigs in Brazil, to be ordered by Petrobras. If Petrobras is not able to meet its need with rigs built in Brazil, the rigs will likely be obtained from the international drilling market. In addition to the successful pre-salt geological trend in the Santos Basin offshore Brazil, a similar pre-salt geologic trend has been identified offshore West Africa, which could lead to increased deepwater drilling in that region over the coming years.

In addition, deepwater drilling economics have been aided in recent years by an expectation of higher average crude oil prices, supported by global population growth and economic expansion and an increased number of deepwater discoveries containing large volumes of hydrocarbons. These improving factors associated with deepwater activity have produced a growing base of development programs requiring multiple years to complete and resulting in long-term contract awards by our customers, especially for projects in the three traditional deepwater basins, and represents a significant portion of our revenue backlog that currently extends into 2017.

Industry uncertainty, due in part to the Deepwater Horizon incident and the U.S. government’s response, and its impact on our clients’ long-term planning horizons has resulted in clients delaying decisions on deepwater drilling requirements. These delayed contracting decisions, together with limited charter of rig time between clients, have contributed to a decline in dayrates for deepwater rigs as more units compete for a reduced number of contract opportunities. The lower utilization and dayrate decline are most pronounced among the conventionally moored deepwater semisubmersibles, which generally have the ability to operate in water depths of up to 6,000 feet and employ less sophisticated features. Dayrates for rigs of this technical specification, where eight units in the global fleet are currently idle, have weakened considerably from peak levels experienced during 2008 and could experience further weakness through 2010 and into 2011 as a growing number of rigs complete contracts. Dayrates for the industry’s technologically advanced deepwater rigs have also declined from the peak levels in 2008, including those possessing dynamic positioning technology and more efficient well construction features. However, due to operator preference for the advanced capabilities of these units, it is expected that utilization will remain high over the coming years, but dayrates could adjust lower in the near-term for several reasons, including continued delay by clients of the commencement of offshore programs, especially the large development programs that typically take multiple years to complete. Also, the increase in deepwater drilling capacity, particularly in 2011 when as many as 13 uncommitted new deepwater rigs are expected to complete construction programs and enter the active global fleet, could place dayrates for these rigs under additional pressure. Many of the 13 uncommitted units are currently owned by new entrants to our business, possessing limited industry knowledge, global operational infrastructure and client relationships. We believe these attributes along with higher customer and regulatory standards are important considerations for our clients and will allow us to compete effectively for contract opportunities during this period of increased industry supply. However, we estimate that the Deepwater Horizon incident and resulting regulatory actions related to drilling in the U.S. Gulf of Mexico could continue to drive the relocation of a number of the deepwater rigs in the region to international locations, which would place dayrates and utilization for rigs in these locations under further pressure. As of September 30, 2010, four deepwater rigs in the U.S. Gulf of Mexico have been identified for relocation to other regions with additional relocations possible.

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

Our Midwater segment consists of six semisubmersible rigs. Five of the rigs currently operate offshore Brazil, with one rig, the Pride South Seas, cold stacked in South Africa. We currently have 81% of our available rig days in the final quarter of 2010 contracted for our midwater fleet, with 78% in 2011, 35% in 2012 and 14% in 2013. Utilization of the industry’s midwater fleet was 88% at September 30, 2010, with 14 rigs idle around the world compared to utilization of 85% at the same time in 2009, when 17 rigs were idle. Economic instability and uncertainty in crude oil markets during 2009 resulted in a growing number of inactive midwater rigs in the year, and this reduced level of activity has carried into 2010, contributing to a more challenging dayrate environment. A modest increase in midwater activity through the third quarter of 2010 has been most evident in Australia and in the U.K. and Norwegian sectors of the North Sea as the areas have responded positively to continued price stability for North Sea Brent crude oil, which averaged $77 per barrel in the third quarter of 2010, compared to $68 per barrel in the third quarter of 2009. A developing weakness in the deepwater rig segment for conventionally moored deepwater rigs could bring additional pressure to utilization and dayrates over the balance of 2010 and into 2011, as these more capable rigs are forced to bid reduced dayrates on work programs in shallower water depths in an attempt to remain active, thereby eliminating a contract opportunity that may have otherwise been available to a midwater unit. Also, the number of midwater rigs located in the U.S. Gulf of Mexico has declined significantly over the past 10 years due primarily to the risk of mooring system failures during hurricane season, marginal geologic prospects and more attractive opportunities in other regions, such as Brazil. We expect the worldwide supply of available midwater rigs to exceed client demand for the balance of 2010 and into 2011 with most contract opportunities characterized by short durations of six months or less. In addition, we expect a growing number of idle units as the short contract durations that are expected to persist into 2011 will not support the capital expenditures needed to complete reactivation programs on many of the idle units.

Our Independent Leg Jackup segment, consisting of seven rigs, currently operates in the Middle East. We currently have 17% of our available rig days in the last quarter of 2010 contracted for our independent leg jackup fleet, with 21% contracted in 2011, and 14% contracted in 2012 and 2013. Five of our seven standard independent leg jackup rigs are currently idle, with limited prospects for work through the balance of 2010 and into 2011. Customer demand for jackup rigs declined steadily in 2009 while contract backlogs fell throughout the industry’s existing fleet of rigs and incremental capacity surged. As of September 30, 2010, 91 independent leg jackup rigs were idle in the global fleet out of a total fleet of 405, representing segment utilization of 78%. The addition of new jackup rig capacity in the industry represents a long-term threat to the segment, due in part to the geologic maturity of many shallow water drilling basins around the world, in contrast to the early stages of exploration and development characterized by most of the world’s deepwater basins. Since 2007, 80 jackup rigs have been added to the global fleet, with another 38 rigs expected to be added by the end of 2012. As of September 30, 2010, 24 of the 38 expected incremental jackup rigs were without contracts. Despite the overall decline in jackup fleet utilization since 2009, customer demand for high specification units has shown improvement in 2010, with utilization of these rigs exceeding 85% and dayrates registering modest gains. These units possess advanced features, including greater hook loads, extended cantilever reach and the ability to drill wells with high pressure and temperature characteristics, such as those common in the UK and Norwegian sectors of the North Sea. Conversely, demand for the industry’s standard international-class jackup rigs, which possess dated features and technology, has declined significantly since 2009 and is expected to be flat to lower through the remainder of 2010 and into 2011.

We experienced approximately 150 and 500 out-of-service days for shipyard maintenance and upgrade projects for the three and nine months ended September 30, 2010, respectively, for our existing fleet as compared to approximately 215 and 385 days for the three and nine months ended September 30, 2009. For 2010, we expect the total number of out-of-service days to be approximately 590 as compared to 660 days for 2009. The decline in expected out-of-service days in 2010 is primarily due to a reduction of planned shipyard construction projects in our Deepwater segment, partially offset by an increase of planned projects in our Independent Leg Jackup and Midwater segments.

Backlog

Our contracted backlog at September 30, 2010 totaled approximately $6.4 billion, with $2.9 billion attributable to our ultra-deepwater drillship construction projects. We expect approximately $1.6 billion of our total backlog at September 30, 2010 to be realized in the next 12 months. Our backlog at December 31, 2009 was approximately $6.9 billion. We calculate our backlog, or future contracted revenue for our offshore fleet, as the contract dayrate multiplied by the number of days remaining on the contract, assuming full utilization. Backlog excludes revenues for mobilization, demobilization, contract preparation, customer reimbursables and performance bonuses. The amount of actual revenues earned and the actual periods during which revenues are earned will be different than the amount disclosed or expected due to various factors. Downtime due to various operating factors, including unscheduled repairs, maintenance, weather and other factors, may result in lower applicable dayrates than the full contractual operating dayrate, as well as the ability of our customers to terminate contracts under certain circumstances.

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


	For the Years Ending December 31,
	2010⁽¹⁾			2011			2012			2013
Rig Days Committed
Deepwater		100	%		83	%		67	%		55	%
Midwater		81	%		78	%		35	%		14	%
Independent Leg Jackups		17	%		21	%		14	%		14	%


(1)		Represents the three-month period beginning October 1, 2010.

Segment Review

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In millions)						(In millions)
Deepwater revenues:
Revenues excluding reimbursables	$	212.1		$	189.9		$	649.0		$	634.4
Reimbursable revenues		4.1			1.9			10.6			10.7

Total Deepwater revenues		216.2			191.8			659.6			645.1

Midwater revenues:
Revenues excluding reimbursables		86.1			96.8			269.0			338.9
Reimbursable revenues		0.1			1.4			0.7			4.8

Total Midwater revenues		86.2			98.2			269.7			343.7

Independent Leg Jackups revenues:
Revenues excluding reimbursables		24.5			72.6			76.9			220.7
Reimbursable revenues		0.2			0.2			1.0			0.6

Total Independent Leg Jackups revenues		24.7			72.8			77.9			221.3

Other		19.0			21.7			51.8			65.5
Corporate		0.1			1.6			0.3			1.8

Total revenues	$	346.2		$	386.1		$	1,059.3		$	1,277.4


Earnings (loss) from continuing operations:
Deepwater	$	66.9		$	71.8		$	237.4		$	300.9
Midwater		12.5			25.7			56.1			121.1
Independent Leg Jackups		(0.2	)		32.6			(13.5	)		102.3
Other		2.1			1.6			3.7			3.9
Corporate		(25.3	)		(31.6	)		(84.2	)		(91.4	)

Total	$	56.0		$	100.1		$	199.5		$	436.8

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


	Three Months Ended September 30,										Nine Months Ended September 30,
	2010					2009					2010					2009
	Average					Average					Average					Average
	Daily		Utilization			Daily		Utilization			Daily		Utilization			Daily		Utilization
	Revenues (1)		(2)			Revenues (1)		(2)			Revenues (1)		(2)			Revenues (1)		(2)
Deepwater	$	294,800		95	%	$	343,200		76	%	$	322,500		92	%	$	338,600		87	%
Midwater	$	269,800		58	%	$	264,100		67	%	$	268,100		61	%	$	260,900		80	%
Independent Leg Jackups	$	92,400		41	%	$	123,100		92	%	$	97,000		42	%	$	123,100		94	%


(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 $24.4 million, or 13%, for the three months ended September 30, 2010 over the comparable period in 2009. The increase in revenues is primarily due to the Deep Ocean Ascension, which BP E&P agreed to place on a special standby dayrate of $360,000 beginning in August 2010, and increased utilization of the Pride Carlos Walter and the Pride Portland, which experienced an increase in the number of days worked of 22 and 24 days, respectively. Together, these factors contributed $28.6 million to the increase in revenues in the third quarter of 2010 over the comparable period in 2009. The Pride North America also contributed an incremental $9.7 million in revenues in the third quarter of 2010 as a result of decreased shipyard time—the rig experienced approximately 79 out-of-service days as a result of a scheduled five-year regulatory inspection and client requested upgrades in the third quarter of 2009—in addition to experiencing a higher dayrate in 2010. However, results for the quarter were negatively affected by an on-going dispute with a client relating to the responsibility for payment of the time required for equipment inspection and maintenance at the specific request of the client on an unscheduled basis. As a result, we did not recognize an estimated $30 million of revenues relating to approximately 60 contracted rig days on the Pride North America due to the dispute pending resolution of the matter. The increase in revenues in the third quarter was also partially offset by the Pride South Pacific, which earned an incremental $12.6 million of revenue in the 2009 period resulting from the recognition of mobilization revenues in addition to experiencing a higher dayrate. Average daily revenues decreased 14% for the three months ended September 30, 2010 over the comparable period in 2009 primarily due to the decreased dayrate for the Pride South Pacific and the impact of the disputed revenue for the Pride North America discussed above, partially offset by the commencement of the special standby dayrate of the Deep Ocean Ascension. Earnings from operations decreased $4.9 million, or 7%, for the three months ended September 30, 2010 over the comparable period in 2009 due to the decline in earnings from the Pride South Pacific, an increase in labor costs for our offshore workforce and start-up costs related to the Deep Ocean Ascension, the Deep Ocean Clarion and the Deep Ocean Mendocino. Utilization increased to 95% for the three months ended September 30, 2010 as compared to 76% for the three months ended September 30, 2009 primarily due to an overall decrease in out-of-service time.

Revenues for our Deepwater segment increased $14.5 million, or 2%, for the nine months ended September 30, 2010 over the comparable period in 2009. The increase in revenues is primarily due to higher utilization of the Pride Brazil, which spent time in the shipyard for contractual upgrades in the second quarter of 2009, the Deep Ocean Ascension, which was placed on a special standby dayrate of $360,000 beginning in August 2010, the Pride North America, which operated at a higher dayrate in the 2010 period and the Pride Africa, which experienced an increase in the number of days working in the first nine months of 2010. These factors contributed to an increase in revenues of $52.9 million over the comparable period in 2009. However, the increase from the Pride North America does not give effect to approximately $30 million of revenue, which we did not recognize during the third quarter 2010, due to the on-going dispute with our customer discussed above. This increase in revenues for the first nine months was also partially offset by the Pride South Pacific, which, after completion of its upgrade, commenced a new contract mid-January 2010 at a substantially lower dayrate than its 2009 dayrate and resulted in a $41.3 million decrease in revenues in the first nine months of 2010 over the comparable period in 2009. Average daily revenues decreased 5% for the nine months ended September 30, 2010 over the comparable period in 2009 primarily due to the decreased dayrate for the Pride South Pacific and the impact of the disputed revenue for the Pride North America, partially offset by the commencement of the special standby dayrate of the Deep Ocean Ascension. Earnings from operations decreased $63.5 million, or 21%, for the nine months ended September 30, 2010 over the comparable period in 2009 due to the decline in earnings from the Pride South Pacific, an increase in labor costs for the offshore workforce, and start-up costs related to the Deep Ocean Ascension, the Deep Ocean Clarion and the Deep Ocean Mendocino. Utilization increased to 92% for the nine months ended September 30, 2010 as compared to 87% for the nine months ended September 30, 2009 primarily due to decreased out-of-service time experienced by the Pride Brazil, the Pride Africa and the Pride Portland, partially offset by the increased out-of-service time for the Pride Carlos Walter and the Pride Rio de Janeiro.

Midwater

Revenues for our Midwater segment decreased $12.0 million, or 12%, for the three months ended September 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to lower utilization of the Pride South Seas, which was idle during the third quarter of 2010, and the Pride South America, which underwent a shipyard project in the third quarter of 2010. These factors contributed to a decrease in revenues of $23.4 million over the comparable period in 2009. This decrease in revenues was partially offset by the Sea Explorer, which operated at a substantially higher dayrate and contributed an incremental $15.7 million of revenues in the third quarter of 2010 over the comparable period in 2009. Earnings from operations decreased $13.2 million, or 51%, for the three months ended September 30, 2010 over the comparable period in 2009 due to decreased revenues and higher repair and maintenance costs for the Pride Venezuela, partially offset by incremental earnings associated with the higher dayrate and utilization of the Sea Explorer. Utilization decreased to 58% for the three months ended September 30, 2010 from 67% for the three months ended September 30, 2009 primarily due to the decreased utilization of the Pride South Seas and the Pride South America, partially offset by the increased utilization of the Sea Explorer.

Revenues for our Midwater segment decreased $74.0 million, or 22%, for the nine months ended September 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to lower utilization of the Pride South Seas, which was idle during the entire first nine months of 2010, and the Pride Venezuela, which was in the shipyard for a rig refurbishment project in the first quarter of 2010 that was completed in the third quarter of 2010. These factors contributed to a decrease in revenues of $98.1 million over the comparable period in 2009. This decrease in revenues was partially offset by the Sea Explorer, which operated at a substantially higher dayrate in 2010 over the comparable period in 2009 and contributed an incremental $26.1 million in the first nine months of 2010 over the same period in 2009. Earnings from operations decreased $65.0 million, or 54%, for the nine months ended September 30, 2010 over the comparable period in 2009 primarily due to decreased revenues from the Pride South Seas and the Pride Venezuela, partially offset by incremental earnings associated with the higher dayrate and utilization of the Sea Explorer. Utilization decreased to 61% for the nine months ended September 30, 2010 from 80% for the nine months ended September 30, 2009 primarily due to the decreased utilization of the Pride South Seas, the Pride Venezuela and the Pride South America, partially offset by the increased utilization of the Sea Explorer.

Independent Leg Jackup

Revenues for our Independent Leg Jackup segment decreased $48.1 million, or 66%, for the three months ended September 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to the decreased utilization of some of our fleet resulting from a recent decline in the demand for shallow water rigs. The Pride Pennsylvania, the Pride Wisconsin and the Pride Tennessee remained stacked throughout the third quarter of 2010 and the Pride Hawaii was idle. These four rigs accounted for a $44.3 million decline in revenues over the comparable period in 2009, during which period they were substantially utilized. Additionally, the Pride Cabinda operated under a new contract in the third quarter of 2010 at a dayrate substantially lower than its dayrate in the comparable period in 2009. Average daily revenues decreased 25% for the three months ended September 30, 2010 over the comparable period in 2009 primarily due to the Pride Cabinda, which operated at a significantly lower dayrate in the third quarter of 2010 over the comparable period in 2009. Earnings from operations decreased $32.8 million to a loss of $0.2 million for the three months ended September 30, 2010 compared with earnings of $32.6 million for the comparable period in 2009 due to decreased revenues. Utilization decreased to 41% for the three months ended September 30, 2010 from 92% for the three months ended September 30, 2009, primarily due to the rigs that remained stacked or idle during the third quarter of 2010.

Revenues for our Independent Leg Jackup segment decreased $143.4 million, or 65%, for the nine months ended September 30, 2010 over the comparable period in 2009. The decrease in revenues is primarily due to the decreased utilization of some of our fleet resulting from a recent decline in the demand for shallow water rigs. The Pride Pennsylvania and the Pride Wisconsin remained stacked throughout the first nine months of 2010, and the Pride Tennessee was idle for the first quarter of 2010 and then stacked in the second and third quarters. Additionally, the Pride Hawaii was idle for the majority of the second quarter of 2010 and the entire third quarter, the Pride Cabinda experienced approximately 50 out-of-service days in the first quarter of 2010 while awaiting the commencement of a new contract in March 2010, and the Pride Montana commenced a shipyard project in the first quarter of 2010 that was completed in the second quarter and resulted in 44 out-of-service days. These factors influencing revenues in the first nine months of 2010 were in contrast to the comparable period in 2009, during which period all of our rigs were substantially utilized. Average daily revenues decreased 21% for the nine months ended September 30, 2010 over the comparable period in 2009 primarily due to the Pride Cabinda, which operated at a significantly lower dayrate in the first nine months of 2010 over the comparable period in 2009. Earnings from operations decreased $115.8 million to a loss of $13.5 million for the nine months ended September 30, 2010 compared with earnings of $102.3 million for the comparable period in 2009 due to decreased revenues, primarily due to rigs that remained stacked or idle. Utilization decreased to 42% for the nine months ended September 30, 2010 from 94% for the nine months ended September 30, 2009, also primarily due to the rigs that remained stacked or idle during the first nine months of 2010.

Other Operations

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

Revenues decreased $2.7 million, or 12%, for the three months ended September 30, 2010 over the comparable period in 2009 primarily due to the completion of two management contracts in the third and fourth quarters of 2009, partially offset by increased revenue resulting from the commencement of a new management contract in April 2010 at a significantly higher dayrate. Earnings from operations increased $0.5 million, or 31%, for the three months ended September 30, 2010 over the comparable period in 2009 primarily due to the incremental revenue associated with the new management contract in 2010, partially offset by the decreased earnings associated with the completion of two management contracts in 2009.

Revenues decreased $13.7 million, or 21%, for the nine months ended September 30, 2010 over the comparable period in 2009 primarily due to the completion of two management contracts, in the third and fourth quarters of 2009, partially offset by increased revenue resulting from the commencement of a new management contract in April 2010 at a significantly higher dayrate. Earnings from operations decreased $0.2 million, or 5%, for the nine months ended September 30, 2010 over the comparable period in 2009 primarily due to the factors mentioned above.

Results of Operations

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

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In millions)						(In millions)
REVENUES
Revenues excluding reimbursable revenues	$	337.8		$	379.5		$	1,039.2		$	1,253.0
Reimbursable revenues		8.4			6.6			20.1			24.4

		346.2			386.1			1,059.3			1,277.4


COSTS AND EXPENSES
Operating costs, excluding depreciation and amortization		213.0			210.6			631.9			615.9
Reimbursable costs		7.5			5.8			16.9			21.6
Depreciation and amortization		46.7			39.5			133.4			118.3
General and administrative		22.6			30.2			77.7			85.3
Loss (gain) on sales of assets, net		0.4			(0.1	)		(0.1	)		(0.5	)

		290.2			286.0			859.8			840.6


EARNINGS FROM OPERATIONS		56.0			100.1			199.5			436.8

OTHER INCOME (EXPENSE), NET
Interest expense, net of amounts capitalized		(6.5	)		—			(6.5	)		(0.1	)
Refinancing charges		(16.7	)		—			(16.7	)		—
Interest income		1.1			0.6			2.2			2.6
Other income (expense), net		(6.1	)		(2.7	)		5.6			(3.3	)


INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		27.8			98.0			184.1			436.0
INCOME TAXES		15.0			(18.1	)		(2.9	)		(72.5	)


INCOME FROM CONTINUING OPERATIONS, NET OF TAX	$	42.8		$	79.9		$	181.2		$	363.5

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

Revenues Excluding Reimbursable Revenues. Revenues excluding reimbursable revenues for the three months ended September 30, 2010 decreased $41.7 million, or 11%, over the comparable period in 2009. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for the three months ended September 30, 2010 increased $1.8 million, or 27%, over the comparable period in 2009, primarily due to increased reimbursable revenue related to the Deep Ocean Ascension, the Pride Africa and the Pride Angola, partially offset by decreased reimbursable revenue related to the Sea Explorer.

Operating Costs. Operating costs for the three months ended September 30, 2010 increased $2.4 million, or 1%, over the comparable period in 2009. The increase is largely attributable to our Deepwater segment, which experienced higher labor costs, increased operating costs resulting from the Deep Ocean Ascension, which went on a special standby dayrate in August 2010, and increased startup costs for the Deep Ocean Clarion. Partially offsetting these increases were reductions in labor costs due to lower activity in our Midwater and Independent Leg Jackup segments and due to completion of a managed rig contract in our Other segment.

Reimbursable Costs. Reimbursable costs for the three months ended September 30, 2010 increased $1.7 million, or 29%, over the comparable period in 2009 primarily due to higher reimbursable costs in our Deepwater and Other Segments, partially offset by lower reimbursable costs related to the Sea Explorer.

Depreciation and Amortization. Depreciation expense for the three months ended September 30, 2010 increased $7.2 million, or 18%, over the comparable period in 2009. This increase relates generally to the capital additions in our Deepwater and Midwater segments, including the commencement of depreciation on the Deep Ocean Ascension in August 2010.

General and Administrative. General and administrative expenses for the three months ended September 30, 2010 decreased $7.6 million, or 25%, over the comparable period in 2009 primarily due to (1) $4.8 million associated with lower employee costs, of which $1.5 million related to lower contract labor costs and $3.3 million related to lower employee benefits and termination costs, (2) $1.0 million of lower expenses related to the investigation described under “—FCPA Investigation,” (3) $1.0 million of lower audit and professional service expenses, and (4) $0.6 million of lower corporate facility expenses and travel expenses resulting from our recently implemented cost cutting initiatives.

Loss (Gain) on Sale of Assets, Net. We had a loss on sales of assets of $0.4 million for the three months ended September 30, 2010, and a net gain on sales of assets of $0.1 million for the three months ended September 30, 2009 million, primarily due to the sale of scrap equipment.

Interest Expense. We had $6.5 million of interest expense for the three months ended September 30, 2010 and no interest expense for the three months ended September 30, 2009, due to the incremental interest associated with the issuance of additional long-term debt in 2010, which was partially offset by the capitalization of interest, which totaled $27.7 million and $23.2 million for the three months ended September 30, 2010 and 2009, respectively.

Refinancing Charges. Refinancing charges for the three months ended September 30, 2010 were $16.7 million and primarily included a $12.3 million make-whole premium and $4.1 million write-off of unamortized debt discount and unamortized debt issuance costs upon redemption of our 7 3/8% Senior Notes in September 2010. There were no refinancing charges for the three months ended September 30, 2009.

Other Expense, Net. Other expense, net for the three months ended September 30, 2010 increased $3.4 million to $6.1 million for the first three months of 2010 from $2.7 million for the comparable period in 2009 primarily due to a $3.5 million increase in our foreign exchange loss.

Income Taxes. Our consolidated effective income tax rate for continuing operations for the three months ended September 30, 2010 was (54.0%) compared with 18.5% for the three months ended September 30, 2009. The lower tax rate for the 2010 period was principally the result of lower income from continuing operations in 2010, tax benefits related to the adjustment of intercompany pricing in the completion of our 2009 income tax return during the third quarter of 2010, the catch-up effect of our current lower annual projected tax rate, and an increased proportion of income in lower tax jurisdictions.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Revenues Excluding Reimbursable Revenues. Revenues excluding reimbursable revenues for the nine months ended September 30, 2010 decreased $213.8 million, or 17%, over the comparable period in 2009. For additional information about our revenues, please read “— Segment Review” above.

Reimbursable Revenues. Reimbursable revenues for the nine months ended September 30, 2010 decreased $4.3 million, or 18%, over the comparable period in 2009, primarily due to lower activity in our Midwater segment.

Operating Costs. Operating costs for the nine months ended September 30, 2010 increased $16.0 million, or 3%, over the comparable period in 2009. The increase is largely attributable to our Deepwater segment, which experienced higher labor costs, increased startup and operating costs resulting from the Deep Ocean Ascension, which went on a special standby dayrate in August 2010, and increased startup costs for the Deep Ocean Clarion. Partially offsetting these increases were reductions in labor costs in our Midwater and Independent Leg Jackup segments due to lower activity and due to completion of managed rig contracts in our Other segment.

Reimbursable Costs. Reimbursable costs for the nine months ended September 30, 2010 decreased $4.7 million, or 22%, over the comparable period in 2009 primarily due to lower activity across our fleet.

Depreciation and Amortization. Depreciation expense for the nine months ended September 30, 2010 increased $15.1 million, or 13%, over the comparable period in 2009. This increase relates to capital additions primarily in our Deepwater and Midwater segments, including the commencement of depreciation on the Deep Ocean Ascension in August 2010.

General and Administrative. General and administrative expenses for the nine months ended September 30, 2010 decreased $7.6 million, or 9%, over the comparable period in 2009, primarily due to (1) $4.1 million of lower employee benefits and termination costs, (2) $2.4 million of lower contract labor costs, and (3) $0.9 million of lower expenses related to the investigation described under “—FCPA Investigation.”

Gain on Sale of Assets, Net. We had net gain on sales of assets of $0.1 million for the nine months ended September 30, 2010 and $0.5 million for the nine months ended September 30, 2009, primarily due to the sale of scrap equipment.

Interest Expense. We had $6.5 million of interest expense for the nine months ended September 30, 2010 and $0.1 million for the nine months ended September 30, 2009, primarily due to the incremental interest associated with the issuance of additional long-term debt in 2009 and 2010, which was partially offset by the capitalization of interest, which totaled $73.6 million and $51.7 million for the nine months ended September 30, 2010 and 2009, respectively.

Refinancing Charges. Refinancing charges for the nine months ended September 30, 2010 were $16.7 million and primarily included a $12.3 million make-whole premium and $4.1 million write-off of unamortized debt discount and unamortized debt issuance costs upon redemption of our 7 3/8% Senior Notes in September 2010. There were no refinancing charges for the nine months ended September 30, 2009.

Other Income (Expense), Net. Other income, net for the nine months ended September 30, 2010 increased $8.9 million to $5.6 million for the first nine months of 2010 from an expense of $3.3 million for the comparable period in 2009 primarily due to a $9.0 million increase in our foreign exchange gain.

Income Taxes. Our consolidated effective income tax rate for continuing operations for the nine months ended September 30, 2010 was 1.6% compared with 16.6% for the nine months ended September 30, 2009. The lower tax rate for the 2010 period was principally the result of tax benefits related to the adjustment of intercompany pricing in the completion of our 2009 income tax return during the third quarter of 2010, lower income from continuing operations in 2010, and an increased proportion of income in lower tax jurisdictions.

Liquidity and Capital Resources

Our objective in financing our business is to maintain both adequate financial resources and access to additional liquidity. Our $750 million senior unsecured revolving credit facility provides back-up liquidity to meet our on-going working capital needs. Total long-term debt including the current portion at September 30, 2010 was $1.9 billion, and stockholders’ equity was $4.5 billion, resulting in a debt-to-total-capital ratio of 30%.

During the three months ended September 30, 2010, we used cash on hand, cash flows generated from operations, and net proceeds from our August 2010 $1.2 billion senior notes offering as our primary source of liquidity for funding our working capital needs, debt repayment and capital expenditures. We believe that our cash on hand, including the remaining net proceeds from the August 2010 notes offering, cash flows from operations and availability under our revolving credit facility will provide sufficient liquidity through 2011 to fund our working capital needs and scheduled debt repayments. We expect to fund our remaining commitments under our drillship construction program using some combination of cash on hand, cash flow from operations and, if needed, borrowings under our revolving credit facility. In addition, we will continue to pursue opportunities to expand or upgrade our fleet, which could result in additional capital investment. We may also in the future elect to return capital to our stockholders by share repurchases or the payment of dividends.

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

Sources and Uses of Cash

Cash flows from operating activities

Cash flows from operating activities were $265.3 million for the nine months ended September 30, 2010 compared with $532.1 million for the comparable period in 2009. The decrease of $266.8 million was primarily due to a reduction of income from continuing operations.

Cash flows used in investing activities

Cash flows used in investing activities were $1,047.8 million for the nine months ended September 30, 2010 compared with $764.1 million for the comparable period in 2009, an increase of $283.7 million. The increase is primarily attributable to an increase in expenditures incurred towards the construction of our ultra-deepwater drillships.

Cash flows from financing activities

Cash flows from financing activities were $659.0 million for the nine months ended September 30, 2010 compared with $477.0 million for the comparable period in 2009, an increase of $182.0 million. The increase in cash flows from financing activities was primarily due to the issuance in August 2010 of our 6 7/8% Senior Notes due 2020 and our 7 7/8% Notes due 2040, which resulted in net proceeds of $1.2 billion. We also redeemed our 7 3/8% Notes due 2014 at a price of 102.458% of the $500.0 million principal amount, plus accrued and unpaid interest to the redemption date, which resulted in total cash paid of $517.4 million. In June 2009, we issued our 8 1/2% Senior Notes due 2019, which resulted in net proceeds of $492.4 million. Cash used for scheduled debt repayments totaled $22.3 million for the nine months ended September 30, 2010 and 2009. We also received proceeds of $7.5 million and $6.3 million from employee stock transactions in the nine months ended September 30, 2010 and 2009, respectively.

Working Capital

As of September 30, 2010, we had working capital of $550.4 million compared with $661.8 million as of December 31, 2009. The decrease in working capital is primarily due to expenditures of approximately $815 million incurred towards the construction of our four ultra-deepwater drillships, partially offset by the net proceeds from the issuance of our 6 7/8% Senior Notes and our 7 7/8% Senior Notes and the redemption of our 7 3/8% Senior Notes in the third quarter of 2010.

Available Credit Facility

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

Other Outstanding Debt

As of September 30, 2010, in addition to our credit facility, we had the following long-term debt, including current maturities, outstanding:

	•		$500.0 million principal amount of 8 1/2% senior notes due 2019;

	•		$900.0 million principal amount of 6 7/8% senior notes due 2020;

	•		$300.0 million principal amount of 7 7/8% senior notes due 2040; and

	•		$174.7 million principal amount of notes guaranteed by the United States Maritime Administration.

Other Sources and Uses of Cash

We expect our purchases of property and equipment for 2010, excluding our commitments related to our drillship construction projects, to be approximately $285 million, of which we have spent approximately $235 million in the first nine months. These purchases have been and are expected to be used primarily for various rig upgrades in connection with new contracts as contracts expire during the year along with other sustaining capital projects. With respect to our drillship construction projects, we made payments of $687 million in the first nine months of 2010, with the total remaining costs estimated to be approximately $810 million. We anticipate making additional payments for the construction of our drillships of approximately $45 million for the remainder of 2010, and approximately $765 million in 2011. These costs exclude rig mobilization costs, capital spares and other start-up costs. We expect to fund our remaining commitments under our newbuild program using some combination of cash on hand, including the net proceeds from our notes offering in August 2010, cash flow from operations, and, if needed, borrowings under our revolving credit facility.

We anticipate making income tax payments of approximately $37 million to $42 million in 2010, of which $32.8 million has been paid through September 30, 2010.

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

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

Letters of Credit

We are contingently liable as of September 30, 2010 in the aggregate amount of $487.1 million under certain performance, bid and custom bonds and letters of credit. As of September 30, 2010, we had not been required to make any collateral deposits with respect to these agreements.

Contractual Obligations

For additional information about our contractual obligations as of December 31, 2009, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Contractual Obligations” in Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2009. As of September 30, 2010, except with respect to the issuance in August 2010 of $900 million aggregate principal amount of 6 7/8% Senior Notes due 2020 and $300 million aggregate principal amount of 7 7/8% Senior Notes due 2040, and the redemption of $500 million aggregate principal amount of 7 3/8% Senior Notes due 2014, there were no material changes to this disclosure regarding our contractual obligations made in the annual report.

Accounting Pronouncements

Forward-Looking Statements

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

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

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

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

	•		customer requirements for drilling capacity and customer drilling plans;

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

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

	•		future asset sales;

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

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

	•		business strategies;

	•		expansion and growth of operations;

	•		future exposure to currency devaluations or exchange rate fluctuations;

	•		expected or future indemnification under our drilling contracts;

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

	•		future operating results and financial condition; and

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

We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. These statements are subject to a number of assumptions, risks and uncertainties, including those described under “— FCPA Investigation” above, in “Risk Factors” in Item 1A of our annual report on Form 10-K for the year ended December 31, 2009 and Item 1A of Part II of our quarterly report on Form 10-Q for the quarter ended June 30, 2010 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, including acceptance delays, or defaults by our customers;

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

	•		changes in laws and regulations; and

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposure to interest rate risks, see “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of our annual report on Form 10-K for the year ended December 31, 2009. There have been no material changes to the disclosure regarding our exposure to certain market risks made in the annual report.

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

Item 4. Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this quarterly report. Based upon that evaluation, our President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer concluded that our disclosure controls and procedures as of September 30, 2010 were effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

There were no changes in our internal control over financial reporting that occurred during the third quarter of 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

The information set forth in Note 10 of our Notes to Unaudited Consolidated Financial Statements included in Item 1 of Part I of this quarterly report is incorporated by reference in response to this item.

Item 1A. Risk Factors

For additional information about our risk factors, see Item 1A of our annual report on Form 10-K for the year ended December 31, 2009 and Item 1A of Part II of our quarterly report for the quarter ended June 30, 2010.

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

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

Total

Number of

Maximum

Shares

Number of

Purchased as

Shares That

Part of a

May Yet Be

Total Number

Average

Publicly

Purchased

of Shares

Price Paid

Announced

Under the

Period

Purchased⁽¹⁾

Per Share

Plan ⁽²⁾

July 1-31, 2010

454

22.71

N/A

August 1-31, 2010

—

N/A

September 1-30, 2010

—

N/A

Total

454

22.71

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.

In addition, in May 2010, we acquired 2,660 shares of common stock in payment of the exercise price of options exercised by one of our directors. Under the applicable option award agreement, the shares were valued at $27.49, the closing stock price on the NYSE on the exercise date.

Item 6. Exhibits***


4.1*		Amended and Restated Revolving Credit Agreement dated as of July 30, 2010 among Pride, the lenders from time to time parties thereto, Citibank, N.A., as administrative agent for the lenders, Natixis and Wells Fargo Bank, National Association, as syndications agent for the lenders, Bank of America, N.A., as documentation agent for the lenders, and Citibank, N.A., Natixis and Wells Fargo Bank, National Association, as issuing banks of the letters of credit thereunder.

4.2*		Joinder Agreement dated as of October 28, 2010 among Pride, Citibank, N.A., as administrative agent, and NIBC Bank N.V.

4.3*		Third Supplemental Indenture dated as of August 6, 2010 by and between Pride and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A.), as Trustee.

10.1*†		First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (as amended and restated).

12*		Computation of Ratio of Earnings to Fixed Charges.

31.1*		Certification of Chief Executive Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32*		Certification of the Chief Executive and Chief Financial Officer of Pride pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase

101.LAB**		XBRL Taxonomy Extension Label Linkbase

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase

101.DEF**		XBRL Taxonomy Extension Definition Linkbase


*		Filed herewith.

**		Furnished herewith.

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

†		Management contract or compensatory plan or arrangement.

INDEX TO EXHIBITS


4.1*		Amended and Restated Revolving Credit Agreement dated as of July 30, 2010 among Pride, the lenders from time to time parties thereto, Citibank, N.A., as administrative agent for the lenders, Natixis and Wells Fargo Bank, National Association, as syndications agent for the lenders, Bank of America, N.A., as documentation agent for the lenders, and Citibank, N.A., Natixis and Wells Fargo Bank, National Association, as issuing banks of the letters of credit thereunder.

4.2*		Joinder Agreement dated as of October 28, 2010 among Pride, Citibank, N.A., as administrative agent, and NIBC Bank N.V.

4.3*		Third Supplemental Indenture dated as of August 6, 2010 by and between Pride and The Bank of New York Mellon (as successor to JPMorgan Chase Bank, N.A.), as Trustee.

10.1*†		First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (as amended and restated).

12*		Computation of Ratio of Earnings to Fixed Charges.

31.1*		Certification of Chief Executive Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer of Pride pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32*		Certification of the Chief Executive and Chief Financial Officer of Pride pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase

101.LAB**		XBRL Taxonomy Extension Label Linkbase

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase

101.DEF**		XBRL Taxonomy Extension Definition Linkbase


*		Filed herewith.

**		Furnished herewith.

†		Management contract or compensatory plan or arrangement.


	Page
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements		3

Consolidated Balance Sheets — September 30, 2010 and December 31, 2009		3

Consolidated Statements of Operations — Three and Nine months ended September 30, 2010 and 2009		4

Consolidated Statements of Cash Flows — Nine months ended September 30, 2010 and 2009		6

Notes to Unaudited Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		23

Item 3. Quantitative and Qualitative Disclosures About Market Risk		45

Item 4. Controls and Procedures		46

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		46

Item 1A. Risk Factors		46

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		46

Item 6. Exhibits		47

Signatures		48

Exhibit 4.1
Exhibit 4.2
Exhibit 4.3
Exhibit 10.1
Exhibit 12
Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


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



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